The Issue The issue is whether to approve an application by Respondent, Dan R. Hughes Company, L.P. (applicant or Hughes), for an oil well drilling permit authorizing the drilling of an exploratory oil well in Collier County, Florida.
Findings Of Fact The Parties Mosher resides on a three-acre lot at 4695 26th Avenue Southeast, Naples, Florida. His residence is around 2,500 feet west of the proposed wellsite, but Mosher says that the eastern edge of his lot "might be 2,000 feet" from the drilling site. He has not, however, measured the actual distance to confirm this assertion. Preserve is a Florida non-profit corporation whose purpose is to educate the public on issues affecting the preservation and protection of the environment, particularly the environment of south and southwest Florida. It was formed in response to Hughes' intention to drill for oil in the area. The corporation is not a membership organization; rather, it has around 25 non-member, active volunteers, six member directors, and an unknown number of donors. Excluding Mosher, the other member directors live between three and ten miles away from the proposed wellsite. The record does not show where the 25 volunteers reside. The corporate representative testified that four directors, including Mosher, regularly use the Florida Panther National Wildlife Refuge (Refuge) to observe wildlife and habitat. However, the public access point to the Refuge appears to be at least several miles from the wellsite. Based upon an email survey, he stated that a "substantial number [around 36] of donors and volunteers utilize the panther refuge," but he was unaware of when, or how often, this occurred. About every six weeks, meetings are conducted at Mosher's home, which are attended by some, but not all, of the directors and volunteers. Schwartz's primary residence is in Lake Worth (Palm Beach County) where he serves as the unpaid executive director of the South Florida Wildlands Association.3 He sometimes provides paid tours in the Everglades and Big Cypress Swamp and has led "numerous" free hikes into panther habitat to look for signs of panthers. These hikes are limited to the hiking trails in the southeast corner of the Refuge, which is the only area that can be accessed by the public. He represented himself as an advocate for the protection of wildlife habitat in the greater Everglades, with a particular interest in the Florida panther. Hughes is a Texas limited partnership engaged in the business of oil and gas exploration, which is registered to do business in the State of Florida. Hughes has applied for a permit to drill an exploratory well for oil in Collier County. If the well is commercially viable, Hughes must apply for an operating permit at a later time. The Department has jurisdiction to issue permits for the drilling and exploring for, or production of, oil under part I, chapter 377. Pursuant to that authority, the Department reviewed the oil and gas well drilling permit application. The Application and Project After the application was deemed complete by the Department, it was distributed for comment to a number of local, state, and federal agencies. While some commented on the application, no agency had any unresolved concerns at the end of the application process. Hughes met all rule requirements for performance bonds or securities, and it provided all information required by rule. The proposed site is located on the southeast corner of an active farm field in the Big Cypress Swamp watershed, just north of a speedway now used as a test track. Surface holes for oil wells are commonly located on farm land, and farm fields are compatible with oil wells. Based upon a mineral lease between Hughes and the owner of the land, Collier Land Holdings, Ltd., Hughes has the right to locate and drill the well at the proposed surface hole location. The Refuge was established by Congress in 1989 to protect the Florida panther and its habitat and is located approximately 20 miles east of Naples. Around 98 percent of the Refuge is closed to any public activity. The project is consistent with the comprehensive conservation plan for the Refuge prepared by the United States Fish and Wildlife Service (USFWS), in that the plan recommends "slant drilling" off of the Refuge. Although Mosher and Preserve argue that the drill hole should be moved further east into wetlands, and Schwartz contends that it should be moved further west away from the Refuge, the proposed location of the drilling pad and project site is reasonable with respect to the nature, appearance, and location of the proposed drilling site. Likewise, the location is reasonable with respect to the type, nature, and extent of Hughes' ownership. The proposed activity can best be characterized as a "resource play," where an operator drills toward a known resource. This is distinguished from a wildcat operation, where the operator is drilling in an unproven area. Hughes proposes to target the rubble zone (i.e., the lower zone) within the lower Sunniland formation, a geologic formation thousands of feet below the ground surface that runs through southwest Florida. Hughes will first drill a vertical pilot hole and then drill horizontally from the hole bottom in a southeast direction toward a formerly drilled oil well known as the Tribal Well. In order to increase the probability of locating commercially available petroleum, Hughes plans to proceed from west to east in order to arrive at a perpendicular direction of existing limestone fractures as the drilling approaches the Tribal Well. When that well was drilled vertically into the rubble zone in the 1970s, oil rose to the ground surface. Thus, the indicated presence of oil is sufficient to warrant and justify the exploration for oil at this location. The proposed depth of the pilot hole is 13,900 feet measured depth (MD/13,900 feet true vertical depth (TVD)), which will allow assessment of the upper Sunniland, lower Sunniland, and Pumpkin Bay Formations. If the evaluation determines that the well will likely be commercially productive, Hughes will complete a 4,100-foot horizontal leg in the lower Sunniland rubble zone with a landing depth at 12,500 feet MD/12,064 TVD and a total depth of 16,600 feet MD/12,064 feet TVD. The footprint for the drilling pad will be 225 feet by 295 feet, or 2.6 acres, with a two-foot earthen berm around the perimeter of the operating area to contain all water on the site. A secondary containment area within the perimeter of the site will be covered by high-density polyethylene to contain and collect any accidental spills. A drilling rig, generators, and other drilling equipment will be on the pad during drilling operations. A maximum of 20 persons will be at the site, and then only for one day of operations. At all other times, Hughes anticipates there will be a five-person drill crew plus support personnel on site. After drilling, Hughes will remove its equipment. Once the access road is built and the equipment put in place, the drilling activities will take place 24 hours per day, seven days per week, and will be completed in approximately 60 to 70 days. The on-site diesel generators will run simultaneously 24 hours per day while drilling is taking place. The pad will be illuminated at night with lights on the drilling derrick and throughout the pad. Construction of the drilling pad will require trucking around 12,000 to 14,000 cubic yards of fill to the drilling location. Additional traffic for bringing in fill, piping, and related equipment will occur, but the exact amount of traffic is unknown. The South Florida Water Management District (SFWMD) previously approved an environmental resource permit (ERP) to allow the construction and operation of a surface water management system on Camp Keais. The United States Army Corps of Engineers (USACE) also permitted the same system under the Clean Water Act. The latter permit requires mitigation for wetlands and Florida panther habitat compensation. Based on the proposed wellsite, the SFWMD modified the ERP to allow a culvert and access to the proposed wellsite. In addition to the oil drilling permit application, Hughes has applied for two water well drilling permits from the SFWMD, and an injection well drilling permit. Petitioners and Intervenor's Objections The challengers have raised a number of objections that they assert require denial of the application. Conflicting testimony was presented on these issues, which has been resolved in Respondents' favor as being the more credible and persuasive testimony. Mosher and Preserve Mosher and Preserve raise two broad objections. First, they contend that hydrogen sulfide gas (H2S) is likely to be encountered in the drilling of the proposed well. They further contend that the H2S contingency plan submitted by Hughes is not sufficient to evacuate the public in the event of an incident where H2S is uncontrollably released under pressure. Second, they contend that the Committee did not review the application under the process contemplated by section 377.42(2). Except for these two objections, they agree that no other issues remain. See TR., Vol. I, p. 33. Within the petroleum industry, drilling operators create H2S plans when there is reason to believe that the operator may encounter H2S while drilling. This practice is codified in Florida Administrative Code Rule 62C-27.001(7), which requires a contingency plan only when H2S is "likely" to be encountered while drilling. The plan must "meet generally accepted industry standards and practices," and it must contain measures "for notifying authorities and evacuating civilians in the event of an accident." Id. See also rule 62C-26.003(3), which requires a contingency plan "if appropriate." The plan is prepared for two main users: the personnel working at the drilling site; and local emergency management officials, who must plan and train for the implementation of emergency activities. The parties agree that the "generally accepted industry standards and practices" for the oil and natural gas industry are found in the operating standards and recommended practices adopted by The American Petroleum Institute (API), a trade association for the oil and natural gas industry. Recommended Practice 49 (API 49) is the generally accepted industry standard for oil and gas drilling operations likely to encounter H2S and was relied upon by all parties throughout the hearing. The standard includes guidance on personnel protection measures, personnel training, personnel protection equipment, and community contingency planning. API 49 recommends the use of a community warning and protection plan when atmospheric H2S exposures beyond the well site could exceed potentially harmful exposure levels and could affect the general public. Mosher/Preserve's expert opined that H2S might be encountered at levels as high as 21 percent (210,000 parts per million (ppm)) in southwest Florida, and that "it's quite likely" H2S would be encountered at the proposed wellsite. At the same time, however, he agreed with the assessment of Respondents' experts that the likelihood of encountering H2S at this site was merely "possible," "sporadic," and "unlikely," and that there was "zero" potential of a severe H2S release under high pressure. Florida has two major oil producing areas: the Sunniland Trend in southwest Florida and the Smackover formation near Jay, Florida, in the northwest part of the state. Unlike the Smackover formation which has higher temperatures and pressures and a high concentration of H2S, the Sunniland Trend has normal temperatures and pressures and a sporadic presence of H2S. Less than two percent of wells in southwest Florida have been reported to contain H2S, and those reports relate to production wells where bacteria (biological contamination) was likely introduced into the formation during production. Of over 300 oil wells drilled in southwest Florida, only six were reported to have encountered H2S. Notably, the Tribal Well, located 1.5 miles to the southeast of the proposed site, encountered relatively low pressure during drilling and had no H2S, and another well located 12 miles to the north likewise had no high pressure or H2S. It is unlikely that Hughes will encounter high pressure or H2S if it drills at the proposed site. Even though it is unlikely that high pressure or H2S will be encountered during the drilling of this proposed well, Hughes still submitted an H2S contingency plan as part of the drilling application. The Department determined the plan provided an effective design to detect, evaluate, and control any hazardous release of H2S. In response to public concerns, in January 2014 Hughes revised its plan to provide more protections. The revised plan exceeds the guidance provided in API 49. The revised plan clarifies and adds multiple protections, including implementing the plan at a vertical depth of 9,000 feet, which is 2,700 feet before the zone that Mosher claims could contain H2S; clarifying that an H2S alarm notification at 15 ppm would result in an instant well shut-in (i.e., closure of the well) to prevent the escape of H2S; instituting a reverse 911 call system to allow local officials to notify the public by telephone of any incident; creating an air dispersion model to understand the likelihood of public exposure; and adding H2S scavengers to the drilling mud. Adding H2S scavengers in the mud is a protective measure. Specifically, the zinc oxide scavengers will react with H2S to create benign zinc sulfide and water. Even if H2S is present in the formation, the H2S scavengers will neutralize the H2S before it could reach the surface. The H2S scavengers will effectively eliminate the likelihood of H2S escaping from the well during drilling operations. The drilling plan requires the Trinity C formation (which Hughes estimated will begin at a depth of around 11,850 feet) to be cemented off and sealed once drilled. This formation will not be encountered in the first 15 or 20 days of drilling. Once encountered, the formation will be exposed for only four to six days. Even if H2S were encountered during this short exposed duration, all of the protections included in the revised plan would be in place, including overbalanced drilling mud, H2S scavengers, blowout preventers, H2S monitors, and alarms. When wells are drilled, there are numerous personnel monitoring the drilling fluid, or mud, which is designed not only to carry cuttings to the surface, but more importantly to act as a barrier to keep fluids or gasses in the geologic formation. The mud is weighted with additives to combat reservoir pressures. Drill operators want the same amount of mud pumped into the hole as the amount flowing back up. If more fluid is flowing back up, then the mud is not heavy enough to hold back the fluids or gasses encountered. If this imbalance occurs, the well is shut- in immediately and the mud weight is adjusted. A shut-in can be accomplished in just a few seconds. Anything in a shut-in well will stay in the well. Hughes' normal drilling plan is to slightly overbalance the mud weight. This ensures that nothing unintentionally escapes from the reservoir. Mosher and Preserve contend that if H2S is encountered, dangerous concentrations of H2S would leave the wellsite. In response to this type of concern, as part of the revised plan, Hughes conducted an air dispersion model using the methodology provided by API 49. The API 49 model is a Gaussian model with default values reflecting the worst-case exposures. The peer- reviewed and conservative model calculated by Dr. Walker looked at H2S concentrations of 10, 15, and 100 ppm. At the extreme case, a 100-ppm release at the well would be reduced below 10 ppm within about 20 feet from the well and further reduced to one ppm within 60 feet from the well. Although H2S is unlikely to escape the well, 100 ppm was selected as a precautionary level because this level is an immediate danger to human life and health. Reaching 100 ppm is highly unlikely because at an instantaneous reading of 15 ppm, the well is immediately shut-in. The air dispersion model results demonstrate that atmospheric H2S exposures beyond the wellsite could not exceed potentially harmful exposure levels nor could exposures affect the general public. Thus, even though the plan includes a community warning and protection provision, it is not required under API 49. In an abundance of caution, however, the plan provides for a public notification zone of 2,000 feet in case of an H2S release. This zone is two orders of magnitude beyond the 20- foot, 10 ppm distance dispersion of H2S based on the modeled worse case release and exceeds any required notification zones in other states. The notification boundary is conservative, as compared with industry standards. While Mosher's expert recommended more stringent standards than API 49, he knew of no contingency plan for an oil drilling permit in the United States that included his recommended standards. Mosher's expert testified that based on his review of literature, the lowest observable adverse effect from H2S was at concentrations of 2.1 ppm. Based on a worst case scenario release of 100 ppm of H2S, the gas would disperse to a concentration of 2.1 ppm in less than 40 feet from the well. The property boundary abutting the neighborhood to the west is over 800 feet from the well. API 49 expressly provides that wellsite personnel should be provided protection devices if concentrations of H2S exceed 10 ppm for an eight-hour time-weighted average. The revised plan requires wellsite personnel to don a self-contained breathing apparatus if the monitors encounter an instantaneous reading of 10 ppm H2S. Instantaneous readings are more protective of human health than the time-weighted averages proposed by Mosher's expert. Using an instantaneous trigger is another area where the revised plan exceeds the recommendation of API 49. The greater weight of evidence demonstrates that the H2S contingency plan meets or exceeds guidance of API 49. The revised plan requires hands-on training for public officials and fire/rescue staff before reaching the depth of 9,000 feet. The revised plan further requires hands-on training and drills related to the procedures for use, and location of, all self- contained breathing apparatus and evacuation procedures. The plan is a complete and accurate contingency plan that will assist operators and local emergency management in the unlikely event of an H2S escape. It exceeds the degree of caution typically employed in industry standards. Mosher and Preserve contend that the plan fails to include specific instructions and training for nearby residents in the event of an emergency. However, emergency plans are designed for use by operators at the facility and the local emergency management officials rather than nearby residents. Thus, the Department did not require the applicant to provide specific instructions for those residents. Mosher and Preserve also contend that the plan fails to adequately describe the evacuation routes in the event of an emergency. However, evacuation routes and the potential closure of roads are normally in the domain of local governments, as the operator and Department have no control over this action. Mosher and Preserve contend that the plan does not include complete and accurate information for all property owners in the area. This is understandable since some property owners either failed to respond to inquiries by Hughes when it assembled the information for the plan or were reluctant to provide any personal information. Recognizing this problem, the Department reviewed the website of the Collier County property appraiser to complete the information. To the extent information on certain parcels may not be complete, Hughes can update that aspect of the plan on an on-going basis before operations begin. If a permit is issued, the Department will continue to coordinate with Collier County and other local emergency management officials for the purpose of planning to implement the contingency plan. Based on the foregoing, the evidence establishes that the probability of a dangerous release of H2S beyond the wellsite is highly remote and speculative in nature. The revised contingency plan is consistent with industry standards and satisfies the requirements of the rule. Schwartz Like Mosher and Preserve, Schwartz agreed that except for the concerns expressed in his amended pleading, no other issues remain. Schwartz first contends that Hughes did not demonstrate sufficient efforts to select a proposed location for drilling to minimize impacts as required by rule 62C-30.005. Subparagraph (2)(b)1. requires that drilling sites be located "to minimize impacts on the vegetation and wildlife, including rare and endangered species, and the surface water resources." In particular, Schwartz is concerned about the potential impact on the Florida panther, an endangered species. Hughes selected the proposed site primarily because of its proximity to the Tribal Well, which had a significant show of oil. In order to increase the chances for commercial production, the horizontal segment of the well needs to be perpendicular to the natural fractures in the limestone. In this location, Hughes must drill horizontally from west to east in the direction of the Tribal Well. Hughes was unable to locate the well on the automotive test track directly south of the agricultural field and west of the Tribal Well because of objections by Harley-Davidson, then the owner of the track. A second proposed location just east of the test track was considered but Harley-Davidson would not grant access from the track to the upland sites on the adjacent location. A third option was to construct a lengthy access road from the north to one of the upland sites just east of the test track. However, this alternative would have resulted in significant impacts to wetlands and native vegetation. The proposed site offers the least amount of environmental impact. It is 1.5 miles from the Tribal Well. It has no federal or jurisdictional wetlands on the site, and groundwater modeling submitted with an application for a water use permit demonstrated that the proposed use of water will not adversely affect surrounding wetlands. The proposed access road and drilling pad will not impact any cypress-mixed forest swamps, hardwood hammocks, mangrove forests, archeological sites, or native ceremonial grounds. Nor will they adversely affect known red-cockaded woodpecker colonies, rookeries, alligator holes, research sites, or pine uplands. The evidence establishes that Hughes chose a site that minimized environmental impacts. Schwartz also contends that the wellsite activities will directly decrease the recovery chances of the Florida panther. According to Schwartz, this decrease will occur because the activities involve creating an access road, truck traffic, noise, lights, and vibrations. He also asserts that the proposed wellsite will result in a small amount of direct habitat loss when the cattle field is converted to a drilling pad. The USFWS has developed a panther scientific habitat assessment methodology. It relies upon peer-reviewed studies that found that panthers will select land cover types while avoiding others. The methodology ranks the value of land cover types from zero to ten based on the potential for panther selection. Applying the USFWS' scoring to the proposed wellsite, an improved pasture area has a value of 5.2, which means the land cover is neither actively selected nor avoided by panthers. The areas to the south and east of the proposed wellsite are forested wetlands and forested uplands, which have substantially higher values that range from 9.2 to 9.5. If converted to an open water reservoir under the Camp Keais ERP, the site value would be zero, the land cover type most avoided by panthers. The underlying USACE permit specifically required panther habitat compensation. Hughes' expert established that the proposed site minimizes impacts on wildlife by avoiding habitat selected by panthers such as wetlands, forested uplands, saw palmetto thickets, fresh water marshes, prairies, and native habitats. Based on a dozen visits to the site for the purpose of conducting vegetation mapping and wildlife surveys, the expert concluded there are no panthers currently known to be living, breeding, or denning on the site. A home range for a panther is the area providing shelter, water, food, and the chance for breeding. The typical home range for a male panther is 209 square miles, and female home ranges average around 113 square miles. The evidence establishes the proposed drilling activity will not interfere with the panthers' use of the site. Approval of the permit will not remove or push any panthers out of their home range. Hughes' expert opined that the four male panthers, which historically traversed the area within a mile of the proposed wellsite, would only likely move through the area every 15 or 20 months or longer. The temporary nature of the drilling activities means the panthers may not even be near the location during that time. If a panther is near the location and frightened by any activities, it will avoid the area, but will eventually return. Based on the large home range of the panther, the temporary activities will not increase the likelihood of intraspecies aggression or decrease panther survivability. The more persuasive evidence is that panthers are adaptable. They are habituated to the drilling operations in southwest Florida based on over a hundred thousand telemetry data points taken near 93 oil wells in the primary zone. Panthers are not threatened by the presence of humans. In fact, they live and den in and around residential communities and active agricultural operations. Panthers need prey, water, and shelter. The drilling activities will not adversely affect prey availability or impact water resources. The proposed wellsite's location within a disturbed agricultural field will not impact the panther's ability to shelter. During the permit review process, the Department requested input from the USFWS, the Florida Fish and Wildlife Conservation Commission (FFWCC), and other interested parties regarding the proposed drilling permit. No formal comments were offered by the USFWS, and its biologist for conservation planning indicated informally that the surface impacts from an oil well are "very minor." Likewise, the FFWCC offered no formal comments on the application. The evidence supports a finding that the proposed permit activities will not affect the panther's use of, or travel to and from, the Refuge. The activities will not affect the panthers' availability of prey or increase panther competition for food or home range territory. The drilling will not adversely affect the panther's breeding, survivability, or the recovery of the species. The only other threatened or endangered species found in the vicinity of the proposed site was an eastern indigo snake, which was located two and one-half miles away and would not travel to the proposed wellsite, as its home range is up to a maximum of 450 acres. Schwartz further contends that section 377.242 requires that the permit be denied because the proposed wellsite is within one mile from the seaward (western) boundary of the Refuge. The Refuge is located entirely inland and does not have a seaward boundary, as contemplated by section 377.242(1)(a)3. Therefore, no drilling will be located within one mile of the seaward boundary of any state, local, or federal park, aquatic preserve, or wildlife preserve. This is consistent with the Department's routine and long-standing interpretation of the statute. Big Cypress Swamp Advisory Committee Petitioners and Intervenor initially contended that the permit should be denied because a meeting of the Committee was never convened pursuant to section 377.42. The Committee, however, met on March 11 and 31, 2014. Although a majority of the Committee voted to recommend that the Department deny the permit on various grounds, the recommendation of the Committee is not binding on the Department, and after consideration, was rejected. In their Proposed Recommended Orders, the opponents now contend that the permit should be denied because the Committee did not meet before the Department issued its proposed agency action. For the reasons stated in the Conclusions of Law, this contention is rejected.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department enter a final order issuing Permit No. 1353H, without further modifications. DONE AND ENTERED this 3rd day of June, 2014, in Tallahassee, Leon County, Florida. S D. R. ALEXANDER Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 3rd day of June, 2014.
The Issue In this proceeding, Florida Power Corporation (FPC) seeks approval to construct and operate 470 MW of natural gas-fired advanced design combined cycle (NGCC) generating capacity at its proposed Polk County Site. Additionally, FPC seeks a determination that the Polk County Site has the environmental resources necessary to support an ultimate capacity of 3,000 MW of combined cycle generating capacity fueled by a combination of natural gas, coal-derived gas and distillate fuel oil. Such an ultimate site capacity certification may be granted pursuant to Section 403.517, Florida Statutes and Rule 17-17.231, Florida Administrative Code.
Findings Of Fact Project Site and Vicinity FPC's proposed Polk County Site is located on approximately 8,200 acres in southwest Polk County, Florida, in an area dominated by phosphate mining activities. The Polk County Site is approximately 40 miles east of Tampa, 3 miles south of Bartow and 3.5 miles northwest of Fort Meade. Homeland, the nearest unincorporated community, lies about one mile to the northeast of the site boundary. The Polk County Site is bounded on the north by County Road (CR) 640 and along the southeast and south by a U.S. Agri-Chemical Corporation (USAC) mine. CR 555 runs north-south through the site. The Polk County Site is comprised of land in four different phases of mining activity: mine pits, clay settling ponds associated with phosphate mining, land which has been mined and reclaimed, and land which has yet to be mined. Approximately one-half of the Polk County Site is subject to mandatory reclamation. Land uses adjacent to the Polk County Site consist almost entirely of phosphate mining activities. One mobile home is located at the intersection of CR 640 and CR 555 approximately 2 miles from the proposed location of the principal generating facilities. General Project Description The initial generating capacity at the Polk County Site will be NGCC units. Under what has been designated as the Case A' scenario, ultimate site development will consist of 1,000 MW of NGCC and 2,000 MW of CGCC generating capacity, for a total of 3,000 MW. Under the alternative Case C scenario, the ultimate site capacity would consist of 3,000 MW of all NGCC capacity. The Case C scenario was initially developed as the worst case scenario for the socioeconomic impact analysis (i.e., the one that would produce the least amount of economic benefit.) The combined cycle units which initially burn natural gas can be modified to burn coal gas if necessary to meet changes in fuel supply or pricing. However, under the proposed ultimate site capacity, CGCC generating capacity will be limited to a maximum of 2,000 MW out of the total of 3,000 MW. At ultimate buildout the major facilities at the Polk County Site will include the plant island, cooling pond, solid waste disposal areas, and brine pond. The plant island will be located on mining parcels SA-11, SA-13 and the northerly portion of SA-12. The plant island ultimately will contain the combined cycle power block, oil storage tanks, water and sewage treatment facilities, coal gasification facilities, coal pile and rail loop, and coal handling facilities. The cooling pond at ultimate buildout will be located in mining parcels N-16, N-15 and N-11B, with a channel through N-11C. Mining parcels N-11C, P-3, Phosphoria, Triangle Lakes and P-2, if not used as a solid waste disposal area, will be used as water crop areas to collect rainfall for supplying the cooling pond. The brine pond will receive wastewater reject from the reverse osmosis (RO) water treatment system and will be located on mining parcel SA-9. Two solid waste disposal areas (SWDA) are planned for ultimate development of the Polk County Site. The SWDAs will be mining parcel SA-8 initially and mining parcel P-2 in later phases, if necessary. Coal gasification slag will be the predominant solid waste to be disposed of in the SWDAs. Other areas included within the Polk County Site are mine parcels N- 11A, N-13, N-9B, Tiger Bay East, Tiger Bay, the northerly 80 acres of N-9, SA-10 and the southerly 225 acres of SA-12. Along with providing a buffer for the Polk County Site facilities, these parcels also will provide drainage to Camp Branch and McCullough Creek. Linear facilities associated with the initial 470 MW of generating capacity at the Polk County Site will include a 230 kilovolt (kV) transmission line upgrade, a reclaimed water pipeline, and a backup natural gas pipeline. Site Selection A comprehensive process was used to select the Polk County Site. The goal of that process was to identify a site which could accommodate 3,000 MW of generating capacity and offer characteristics including: (1) multi-unit and clean coal capability; (2) technology and fuel flexibility; (3) cost effectiveness; (4) compatibility with FPC's commitment to environmental protection; (5) ability to comply with all government regulations; and (6) consistency with state land use objectives. The site selection process included the entire State of Florida. Participants in the site selection process included a variety of FPC departments, environmental and engineering consultants, and an eight-member Environmental Advisory Group (EAG) composed of environmental, educational, and community leaders. In October, 1990, with the concurrence of the EAG, the Polk County Site was selected. The ultimate basis for the selection of the Polk County Site was the disturbed nature of the site as a result of extensive phosphate mining activities. The Polk County Site also is compatible with FPC's load center and transmission line network, and is accessible to rail and highway transportation systems. PSC Need Determination On February 25, 1992, the PSC issued Order No. 25805 determining the need for the first 470 MW of generating capacity at the Polk County Site. The PSC concluded in its order that the first two combined cycle units (470 MW) at the Polk County Site will contribute to FPC's electric system reliability and integrity. It also concluded that the first two units would enable FPC to meet winter reserve margin criteria and to withstand an outage of its largest unit at the time of system peak demand. The PSC stated that it was important for FPC to secure a site to meet future needs and that the first two units would contribute toward this goal. Basis for Ultimate Site Capacity The Site Certification Application (SCA), including the Sufficiency Responses, addressed the impacts associated with 3,000 to 3,200 MW of generating capacity under several scenarios. FPC eliminated or modified several of the scenarios by filing a Notice of Limitations which addressed the capacity and environmental effects of 1,000 MW of NGCC and 2,000 MW of CGCC generating capacity at the Polk County Site. Throughout the SCA, Sufficiency Responses and Notice of Limitations, the capacity constraints and environmental effects were analyzed under a worst case scenario, i.e., the maximum environmental effects that could be expected at ultimate site capacity. An ultimate site capacity determination will significantly reduce the time and expense associated with processing supplemental applications for future units at the Polk County Site under the expedited statutory procedures of the Power Plant Siting Act. This will allow FPC to respond more quickly to changes in growth and demand. An ultimate site capacity determination also provides FPC the assurance that the Polk County Site has the land, air and water resources to support future coal gas-fired generating capacity. Project Schedule and Costs Construction of the initial 470 MW of NGCC generating capacity is scheduled to begin in 1994. These units will go into operation in 1998 and 1999. Based on current load forecasts, it is expected that approximately one 250 MW unit will be added every other year to the Polk County Site. Under this schedule, ultimate site development of 3,000 MW would occur about 2018. Capital investment for the Polk County Site is expected to be approximately $3.4 billion for the 1,000 MW NGCC/2000 MW CGCC Case A' scenario and approximately $1.7 billion for the all NGCC Case C scenario. Project Design Generating units for the Polk County Site will be advanced design combined cycle units firing natural gas and/or coal gas, with low sulfur fuel oil as backup. Each combined cycle unit will consist of one or two combustion turbines (CT), a heat recovery steam generator (HRSG) for each CT and one or two steam turbines (ST). The first 470 MW of generating capacity will consist of two CTs firing natural gas, two HRSGs and one or two STs. At ultimate site capacity, the Polk County Site will consist of 12 CTs, 12 HRSGs, and 6 to 12 STs. A combined cycle unit is a generating system that consists of two sequential generating stages. In the first stage, the natural gas, coal gas or fuel oil is burned to operate the CT. Hot exhaust gas from the CT is passed through the HRSG to produce steam to operate the ST. The CT and steam from the HRSG can be arranged to drive individual generators or a single generator. In later phases of the Polk County Site, up to 2,000 MW of combined cycle generation may be fired on coal gas. The combined cycle units that were initially constructed to operate on natural gas can be modified to operate on coal gas. Under the Case A' scenario, two coal gasification plants would be built to produce coal gas for the combined cycle units. Associated with the coal gasification phase of the project will be the expansion of the plant island to accommodate the storage and handling of coal. Coal will be transported onsite by railroad. A rail loop for coal trains will be constructed on the plant island. It will be sized to accommodate a 100-car coal train. The coal storage area and limestone stockout will be located within the coal loop. Limestone is used in the coal gasification process as a fluxing agent to improve the viscosity of the coal slag, a by-product of the coal gasification process. The coal storage area, including the coal piles and emergency coal stockout system, will be lined with an impervious liner, and runoff from the coal storage area will be recycled to the coal gasification plants. The cooling pond for the Polk County Site will be located north and east of the plant island. Water from the cooling pond will be used for producing steam and condenser cooling. The cooling pond will be constructed initially in mining parcel N-16 and then in parcels N-15 and N-11B for later phases. These areas are mined-out pits which are surrounded by earthen dams. These dams will be upgraded where required to provide stability equivalent to the requirements of Chapter 17-672, Florida Administrative Code, for phosphate dams. Soil and Foundation Stability To evaluate the existing soil conditions at the Polk County Site, more than 165 test borings were made. The plant island is an existing mine pit which has been partially filled with sand tailings from phosphate mining operations. Underlying the sand is the Hawthorn formation which is often used as the base for deep load bearing foundations. Foundations for the heavier loads of power plant facilities will require pile foundations or similar types of deep foundations that will extend into the Hawthorn formation. The potential for sinkhole development at the Polk County Site was investigated by reviewing historic sinkhole records, aerial photographs, well drillers' logs, and by drilling three deep borings at the site. The investigation demonstrated that the potential for sinkhole development at the Polk County Site is low and acceptable for this type of construction. Construction Activities Construction of the Polk County Site will be phased over an approximately 25-year period beginning in 1994. The development of the Polk County Site is expected to take place in seven phases. Changes in the scope or sequence of the individual phases may occur depending on capacity needs over time. During Phase I, the initial earthwork and dewatering activities required for the construction of the plant island and cooling pond will take place. The initial cooling pond and plant island area will be dewatered and fill will be placed in SA-11 and SA-13 for the initial power plant construction. Water from the dewatering activities will be conserved by storage in mining parcels SA-8, SA-9, SA-10, N-15 and the northerly part of SA-12, except for quantities used in IMC's recirculation system. Clay consolidation will commence for other parcels, such as N-11A, N-11B, N-11C, N-13 and N-9B. Phosphate mining and related operations will still function in parcels P-2, P-3, Phosphoria, Triangle Lakes, and N-9. The initial vertical power plant construction for the first 470 MW of generating capacity will take place in Phase II. Water stored in Phase I, along with reclaimed water from the City of Bartow, will be used to fill the cooling pond in parcel N-16. Any excess reclaimed water from the City of Bartow, if necessary, will be stored in the eastern portion of N-16. Mining parcels SA-10, the southerly part of SA-12, and a portion of the offsite Estech Silver City plant site will be configured for drainage enhancement to McCullough Creek. Mining parcel SA-8 will be prepared to receive solid waste and parcel SA-9 will be prepared to receive wastewater from the RO system and neutralization basin. Wildlife habitat creation and enhancement will begin in parcels N-9B and N-13. Phase III of the Polk County Site represents the operation of the power plant from 235 MW to 1,500 MW, currently projected as NGCC capacity. The plant island, which will contain the generating units, will be located on mining parcels SA-11 and SA-13. The cooling pond will be located in N-16 and will receive reclaimed water from the City of Bartow and water crop from mining parcels P-3, Phosphoria, P-2, Triangle Lakes, N-15, N-11B, N-11C, the northerly end of SA-12 and the east end of N-16. Phase IV will encompass the development of the Polk County Site from 1,500 MW to 2,000 MW, currently projected as NGCC capacity. In conjunction with the additional generating units onsite, the cooling pond in N-16 will be enlarged to 1,219 acres. Other portions of the Polk County Site would remain the same as in Phase III. During Phase V, coal gasification is projected to be introduced to the Polk County Site. Generating capacity will be increased to 2,250 MW of which 1,000 MW are projected to be NGCC and the remaining 1,250 MW will be CGCC. To accommodate the coal gasification facilities, the northerly portion of SA-12 would be filled. The balance of the site would remain as described in Phase IV. During Phase VI, the generating capacity at the Polk County Site is projected to increase from 2,250 MW to 3,000 MW. This generating capacity will be a combination of 1,000 MW on NGCC and 2,000 MW on CGCC. During this phase, the cooling pond will be enlarged to 2,260 acres and will include parcels N-16, N-15 and N-11B, and a channel through N-11C. Earthwork will be required in N-15 and N-11B to repair and improve dams, and add slope protection on the dam inner faces and seeding on the exterior faces. Phase VII will be the final phase of the Polk County Site. During this phase, if the solid waste disposal area in mining parcel SA-8 were to become full it would be closed and mining parcel P-2 would be prepared to receive solid waste from the power plant operations. Parcels P-3 and Phosphoria will be available for mitigation, if necessary, as a result of activities in parcel P-2. This phase might not occur if coal slag is successfully recycled. Fuel Supply Fuel for the initial 470 MW of combined cycle generation will consist primarily of natural gas, with light distillate fuel oil as backup. Natural gas will be delivered by pipeline to the Polk County Site at a rate of 3.75 million cubic feet per hour. FPC currently plans to receive natural gas from the proposed Sunshine Pipeline for which certification is being sought in a separate proceeding. The Application for the Sunshine Pipeline was filed with DEP in August 1993. The other source for natural gas will be the backup natural gas pipeline which is being certified in this proceeding as an associated linear facility. Fuel oil will be delivered to the site by tanker truck, and enough fuel oil will be stored onsite for three days of operation for each combined cycle unit. At ultimate development, three 4-million gallon oil tanks will be located on the Polk County Site. All fuel handling and storage facilities, including unloading areas, pump areas, piping system, storage tanks, and tank containment areas will meet the requirements of DEP Chapter 17-762, Florida Administrative Code, and applicable National Fire Prevention Association Codes. At ultimate site development, the combined cycle units would use both natural gas and coal gas as primary fuels, and fuel oil as a backup fuel. As with the initial phase of operation, natural gas will be supplied by pipeline. At 1,000 MW of NGCC capacity, six to eight million cubic feet per hour of natural gas will be required. Coal for the coal gasification units will be delivered by railroad. For 2,000 MW of CGCC generating capacity, approximately 15,000 to 20,000 tons of coal a day will be required. Linear Facilities The initial 470 MW of NGCC generation includes three associated linear facilities: a 230-kV transmission line upgrade, a reclaimed water pipeline, and a backup natural gas pipeline. 230-kV Transmission Line The 230-kV transmission line will be routed from the existing FPC Barcola Substation within the Polk County Site to the FPC Ft. Meade Substation adjacent to CR 630. The transmission line corridor is approximately 1,000 feet wide within the Polk County Site boundary and narrows to 500 feet as the corridor leaves the site. The transmission line corridor follows several linear facilities including an existing transmission line right-of-way, CR 555 and CR 630. Land uses along the corridor are primarily phosphate mining, agricultural and industrial. Wetlands within the transmission line corridor are minimal and are associated primarily with roadside ditches. Where the transmission line crosses McCullough Creek, the creek will be spanned. The 230-kV transmission line will be constructed using single shaft tubular steel poles with a double circuit configuration for two 230-kV circuits. The transmission line structures will range in height from 110 feet to 145 feet. The conductor for the transmission line is a 1590 ACSR conductor that is approximately 1.54 inches in diameter. Conductor span lengths between structures will range from 500 to 900 feet. The transmission line will be constructed in six phases. During the first phase, the right-of-way will be cleared. Clearing in upland areas will be done using mowers and other power equipment. Clearing in wetlands, if necessary, will be accomplished by restrictive clearing techniques. After the right-of-way has been cleared, existing structures which will be replaced with new transmission line structures will be removed by unbolting them from their foundations and removing the structures with a crane. Foundations for new transmission line structures will be vibrated into the ground using a vibratory hammer or placed into an augured hole and backfilled. After the foundations are in place, new structures will be assembled on the foundations using a crane. Insulation and pole hardware will be mounted on the structures after erection. In the fifth phase of construction, conductors will be placed on a structure by pulling the conductors through a stringing block attached to the structure. During the final phase of construction, the structures will be grounded and any construction debris will be removed from the right-of-way. The construction of the 230-kV transmission line is estimated to require approximately 17 weeks. Construction of the transmission line will meet or exceed standards of the National Electrical Safety Code; FPC transmission design standards; Chapter 17- 814, Florida Administrative Code; and the Florida Department of Transportation Utility Accommodation Guide, where applicable. Electric and magnetic fields from the 230-kV transmission line will comply with the standards set forth in Chapter 17-814, Florida Administrative Code. Audible noise from the transmission line should occur only during rainy weather and will not exceed 39.1 dBA at the edge of the right-of-way. Since the transmission line is not located near many residences, interference to television and AM radio reception should be minimal. If interference does occur, it can be identified easily and corrected on an individual basis. Backup Natural Gas Pipeline The backup natural gas pipeline will originate at the Florida Gas Transmission pipeline in Hillsborough County at CR 39. The backup pipeline corridor runs generally east for 18 miles until it enters the Polk County Site at the western boundary of the plant island. The pipeline corridor is 1,000 feet wide and it generally follows linear facilities such as Jameson Road, a Tampa Electric Company transmission line, the CSX Railroad, Durrance Road, and Agricola Road. Several subalternate corridors are proposed in Polk County where the backup natural gas pipeline crosses phosphate mining land. The subalternate corridors, all of which are proposed for certification, are necessary to maintain flexibility in routing the backup natural gas pipeline around active mining operations. The uses of land crossed by the backup natural gas pipeline corridor consist primarily of phosphate mining and some agriculture. There are only two areas of residential land use along the corridor, one along Jameson Road in Hillsborough County, and the other near Bradley Junction along Old Highway 37 in Polk County. Ecological areas crossed by the natural gas pipeline corridor include a portion of Hookers Prairie in Polk County, some isolated wetlands associated with phosphate mining activities, and the South Prong Alafia River near CR 39 in Hillsborough County. The backup natural gas pipeline will consist of a metering facility, a scraper trap for pipeline cleaning, a maximum 30-inch buried pipeline made of high strength steel, a pressure regulating station, a cathodic protection system for corrosion control, and a Supervisory Control and Data Acquisition (SCADA) system to monitor and operate the pipeline. The pipe to be used for the natural gas pipeline will be manufactured in accordance with standards specified in 49 CFR 192 and the industrial standards referenced therein. Pipe thickness will vary depending on the population of the area crossed. External corrosion control for the pipe will be provided by an external coating around the pipe and a cathodic protection system designed to prevent electrochemical corrosion of the pipe. Pipeline sections will be hydrostatically tested before leaving the factory to 125 percent of the design pressure. Activities associated with the construction of the backup natural gas pipeline will include survey and staking of the right-of-way, right-of-way preparation, stringing of the pipe, bending, lineup welding and nondestructive testing, ditching, lowering in of pipeline sections, backfilling, tying in pipeline sections, testing and right-of-way restoration. Construction of the pipeline will take place typically within a 75 foot-wide right-of-way. A wider right-of-way may be required where specialized construction activities, such as jack and bore methods, are used. After construction, the natural gas pipeline will have a permanent 50-foot right-of-way. Where the pipeline crosses federal and state highways or water courses, directional drilling or jack and bore construction methods will be used to minimize disturbance. Where the pipeline crosses the South Prong Alafia River, directional drilling will be used to locate the pipeline underneath the river bed. Pipeline welding will be done by highly skilled personnel who have been qualified in accordance with 49 CFR 192. Pipeline welds will be visually inspected and a percentage of the welds will be x-rayed for analysis. Once the pipeline is constructed, buried and tie-in welds completed, the pipeline will be hydrostatically tested. Hydrostatic testing will use water with a minimum test pressure of 125 percent of maximum operating pressure. Water for hydrostatic testing will be pumped from and returned to the Polk County Site cooling pond. Construction of the pipeline will comply with Title 49 CFR Part 192, Transportation of Natural and Other Gas by Pipelines: Minimum Federal Safety Standards; Chapter 25-12, Florida Administrative Code; Safety of Gas Transportation by Pipeline; and the FDOT Utility Accommodation Guide. After construction of the backup natural gas pipeline, the right-of- way will be restored and a 50-foot-wide permanent right-of-way will be maintained. Line markers will be located along the pipeline at regular intervals and warning signs will be posted where the pipeline crosses roads, railroads, or stream crossings. The estimated cost for the pipeline construction is $611,100 per mile, or $11.2 million for the 18.2 mile pipeline route. Reclaimed Water Pipeline The reclaimed water pipeline will run from the City of Bartow to the cooling pond near the eastern side of the Polk County Site. The reclaimed water pipeline corridor follows the CSX Railroad and U.S. Highway 17/98 south from the southerly Bartow city limit turning west toward the Polk County Site just south of Homeland. Land uses along the corridor include phosphate mining, commercial sites, rural residences and recreation. The corridor does not cross any environmentally sensitive habitats. The reclaimed water pipeline consists of a buried pipe, 24 to 36 inches in diameter, butterfly valves about every mile along the pipeline, and a flow meter. Pumping of reclaimed water will be provided by the Bartow Sewage Treatment Plant. Construction of the reclaimed water pipeline is similar to that of the natural gas pipeline and includes the following activities: survey and staking of the right-of-way, right-of-way preparation, ditching or trenching construction, stringing of the pipe and pipe installation, back filling, hydrostatic testing, and right-of-way restoration. Where the pipeline crosses state or federal highways or railroads, the pipe will be installed by using jack and bore construction. Construction of the reclaimed water pipeline is estimated to cost $500,000 per mile or $5,000,000 for the total length of the pipeline. Construction of the reclaimed water pipeline will comply with the standards in Chapter 17-610, Florida Administrative Code, the Florida Department of Transportation Utility Accommodation Guide, and the EPA Guidelines for Water Reuse Manual. The pipeline will be hydrostatically tested prior to operation. Corrosion control of the pipeline will depend on the material used for the pipeline and the soil conditions. If a polyethylene or a polyvinylchloride material is used, no corrosion control will be necessary. If ductile iron is used, the soil will be tested for corrosive properties and, if necessary, the pipeline will be protected from corrosion with a poly wrap material. Solid Waste Disposal Various types of solid waste will be generated by the operation of the Polk County Site. Depending upon the type of solid waste, disposal may be made in the onsite solid waste disposal areas or it may be disposed of offsite. Waste inlet air filters from the combustion turbines and general waste, such as office waste, yard waste and circulating water system screenings, will be recycled or disposed of offsite at the Polk County North Central Landfill. Solid waste from the well water pretreatment and blowdown pretreatment will be disposed of onsite in the solid waste disposal area to be constructed in mining parcel SA-8. Sulfur, a by-product of coal gasification, will be of marketable grade and will be stored in a molten state onsite and delivered to buyers by rail car or tanker truck. Slag, a by-product of coal gasification, will be the largest volume of solid waste generated at the Polk County Site. Slag is potentially marketable and FPC will make efforts to recycle this by-product as construction aggregate. If slag is not marketable, it will be disposed of in the onsite solid waste disposal areas initially in mining parcel SA-8 and later, if necessary, in parcel P-2. Low volume spent acidic and basic solutions produced in the regeneration of demineralizer resin bed ion exchanges during operation of the facility will be treated in an elementary neutralization unit to render them non-hazardous. Other potentially hazardous waste will be tested and if determined hazardous will be disposed of in accordance with all applicable federal and state laws. Onsite disposal of slag, and well water and blowdown pretreatment solids will be made in the solid waste disposal areas to be constructed in parcels SA-8 and later, if necessary, P-2. These parcels are clay lined impoundments that have clays generally 20 to 40 feet thick. Prior to disposal of any solid waste in a clay settling area, that area will be drained and the clays consolidated. The clays will be probed and if the clay thickness is less than 10 feet it will be refurbished or patched with a synthetic liner. Additionally, a geotextile net will be installed to provide tensile strength to the upper layer of clay. Perimeter leachate collection piping will be installed. Leachate in the interior of the solid waste disposal areas will be monitored and collected by the use of well points to maintain the leachate head at no greater than 4 feet. The solid waste disposal area in parcel SA-8 will be closed by installing a two-foot thick soil cover which will be seeded and graded to provide water crop to parcel N-16. At closure, the leachate level will be pumped down to minimize the residual leachate head. The clay which lines the base of the solid waste disposal areas decreases in permeability as it consolidates and the solids content of the clay increases. In the first 20 to 50 years of consolidation, the hydraulic gradient of the clay is reversed and water will drain upward. Analysis of the clay shows that it would take 60 to 100 years for leachate to seep through the clay liner. After closure and capping of the solid waste disposal area occurs and the leachate residual head is pumped out, leachate is not expected to break through the liner. Based on the design of the solid waste disposal areas and the analysis of the clay, the solid waste disposal areas in parcels SA-8, and later P-2, should provide equivalent or superior protection to that of a Class I landfill under Chapter 17-7.01, Florida Administrative Code. Industrial Wastewater The Polk County Site is designed to be a zero discharge facility. There will be no offsite surface water discharge of contaminated stormwater or cooling pond blowdown. Cooling pond blowdown will be treated first by a lime/soda ash softening pretreatment system. A portion of the softened effluent will be routed to the cooling pond and a portion will be treated further by reverse osmosis (RO). High quality water from the RO system will be reused in the power plant as process water. The reject wastewater from the RO system will be sent to the brine pond for evaporation. In later stages of the Polk County Site operation, the RO reject wastewater will be concentrated prior to disposal in the brine pond. The brine pond will be constructed in parcel SA-9, a waste clay settling pond. Parcel SA-9 has thick waste clay deposits which will act as a liner. A synthetic liner will be placed along the interior perimeter of the brine pond out to a point where the clay is at least 10 feet thick. The synthetic liner will prevent seepage of the brine through the embankment of the brine pond and will provide added protection near the perimeter of the brine pond where the clay liner is thinner. Groundwater Impacts/Zone of Discharge The brine pond and solid waste disposal areas will be located in waste clay settling ponds with thick clay liners. They will be constructed to minimize, if not eliminate, seepage of brine and leachate to groundwater. If brine or leachate should seep through the clay liner, dispersion and dilution will reduce chemical concentrations so that neither primary nor secondary groundwater quality standards will be exceeded at the boundary of the zone of discharge. A zone of discharge has been established for the solid waste disposal area in parcel SA-8, the brine pond in parcel SA-9, and the cooling pond in parcels N-11B, N-15 and N-16. The zone of discharge will extend horizontally 100 feet out from the outside toe of the earthen dam along a consolidated boundary surrounding these facilities and vertically downward to the top of the Tampa member of the Hawthorn Group. A groundwater monitoring plan will be implemented to monitor compliance with groundwater standards at the boundary of the zone of discharge. Surficial Hydrology and Water Quality Impacts The Polk County Site is located along the divide between the Peace River Drainage Basin and the Alafia River Drainage Basin. Water bodies near the site include McCullough Creek, Camp Branch, Six Mile Creek, Barber Branch, and South Prong Alafia River. Mining has disrupted or eliminated natural drainage patterns from the Polk County Site to these water bodies. Currently the only drainage from the Polk County Site to these water bodies is through federally permitted National Pollutant Discharge Elimination System (NPDES) outfalls to McCullough Creek and Camp Branch. To assess the impact to the surficial hydrology of the Polk County Site and surrounding water bodies, the baseline condition was assumed to be the surficial hydrology which would be present under current mandatory reclamation plans for the mining parcels onsite and offsite. The baseline for non-mandatory parcels was assumed to be the minimum reclamation standards under the DEP/Bureau of Mine Reclamation (BOMR) (formerly within the Department of Natural Resources) Old Lands Program and the baseline for non-mandatory offsite parcels was considered to be the existing condition. The one water body onsite for which the baseline condition presently exists is Tiger Bay, which has been reclaimed and released. The baseline condition for the Polk County Site ultimately would include elimination of seepage from N-16 to Tiger Bay and removal of the NPDES outfall weir from Tiger Bay to Camp Branch. These conditions will result in a lowering of the water table in Tiger Bay and the drying out of wetlands in that area. Under current reclamation plans, water bodies also will be created in parcels SA-12 and SA-11. Other than the reclaimed Tiger Bay and Tiger Bay East, DEP, Southwest Florida Water Management District (SWFWMD) and Polk County have not claimed jurisdiction over any of the water bodies onsite within areas in which phosphate mining activities have been or will be conducted. The major construction activities which may impact offsite surface water bodies are the dewatering activities associated with the initial phase of construction. During this period, parcels SA-11, SA-13 and N-16 will be dewatered to allow earth-moving activities to take place. Dewatering effluent will be stored onsite, reused in IMC's recirculation system, or discharged in the event of above-average rainfall. After the earthwork is complete, the water will be returned to N-16. Based on this construction scenario, no adverse impact to offsite surface water bodies is expected from the construction activities associated with the Polk County Site. The Polk County Site has been designed to function as a "zero discharge" facility. No surface water will be withdrawn from or discharged to any offsite surface water body as a result of plant operations. Certain non- industrial areas within the Polk County Site will be designed, however, to provide offsite drainage to enhance flows to McCullough Creek and Camp Branch. Flow to McCullough Creek will be enhanced by drainage from parcel SA-10, an offsite portion of the Estech Silver City Plant Site, and the southerly portion of parcel SA-12. Drainage from parcels N-11A, N-13, N-9B, Tiger Bay East and Tiger Bay will enhance flows to Camp Branch. Additionally, FPC has agreed to explore the possibility of restoring drainage to Six Mile Creek if onsite water cropping produces more water than FPC needs for power plant operations and if such drainage can be accomplished without additional permits. The net effect of the drainage enhancement plans will be to equal or improve flows to McCullough Creek and Camp Branch over the baseline condition for the site. There are several types of surface water systems to be developed on the Polk County Site. Surface water runoff from the plant island, other than that from the coal and limestone storage areas, will be routed to the site runoff pond and then used in the cooling pond as makeup water. Surface water runoff from the coal and limestone storage areas, as well as runoff from the active solid waste disposal area, will be routed to a lined recycle basin and will be used as process makeup water for the coal gasification plant. Surface water runoff from mining parcels N-11C, Triangle Lakes, N-11B and N-15 prior to its use as part of the cooling pond, P-3, Phosphoria, P-2 prior to its use as a solid waste disposal area, and SA-8 after it has been closed as a solid waste disposal area, will be directed to the cooling pond as makeup water. All of the surface water management systems will meet the requirements of the SWFWMD Management and Storage of Surface Water rules. Subsurface Hydrology and Impacts from Water Withdrawal The Polk County Site will use a cooling pond for process water and for cooling water for the combined cycle units and the coal gasification facilities. For the initial 940 MW of generating capacity, makeup water for the cooling pond will come from onsite water cropping and reclaimed water from the City of Bartow. FPC has negotiated an agreement with the City of Bartow for 3.5 or more million gallons per day (mgd) of reclaimed water from its wastewater treatment facility. At ultimate site capacity, the Polk County Site will require up to 23.6 mgd from a combination of offsite sources and groundwater for the operation of the power plant. FPC has agreed with the SWFWMD to obtain at least 6.1 mgd from reclaimed water and other offsite non-potable water sources, including the City of Bartow, for use as makeup water for the cooling pond. The additional 17.5 mgd of water may be withdrawn from the Upper Floridan Aquifer if additional sources of reclaimed water are not available. FPC has identified substantial amounts of reclaimed water that may be available. A limited quantity of potable water from the Upper Floridan Aquifer will be needed to supply drinking water and other potable water needs for power plant employees. Well water from the Upper Floridan Aquifer will be treated, filtered and chlorinated in an onsite potable water treatment system prior to consumption. At ultimate site development, potable water consumption is estimated to average 19,000 gallons per day, with a peak consumption of 36,000 gallons per day. As an alternative, FPC may connect with the City of Bartow or the City of Fort Meade potable water system. The subsurface hydrology of the Polk County Site consists of three aquifer systems. The uppermost system is the surficial aquifer which is located in the upper 20 to 30 feet of soil. Due to mining operations, the surficial aquifer has been removed from the site except beneath highway rights-of-way and portions of some dams. Below the surficial aquifer lies the intermediate aquifer which is comprised of an upper confining layer approximately 120 feet thick, a middle water bearing unit about 60 feet thick, and a lower confining unit about 80 to 100 feet thick. This aquifer system provides potable water to some small quantity users in the area. Below the intermediate aquifer is the Floridan Aquifer, which consists of the Upper Floridan Aquifer, a discontinuous intermediate confining unit, and the Lower Floridan Aquifer. The Upper Floridan Aquifer provides a larger source of potable water for the area. The Lower Floridan Aquifer is characterized by poorer quality water and has not been used generally for water supply. The principal impact to groundwater from construction of the Polk County Site will be from the dewatering activities in parcels N-16, SA-11 and SA-13. This impact, if not mitigated, could result in the lowering of groundwater levels in the surficial aquifer in adjacent wetlands. During construction, recharge trenches will be constructed in certain locations near wetlands. Modeling analysis demonstrates that the recharge trenches will adequately mitigate any offsite groundwater impacts that otherwise would be caused by construction dewatering. The principal groundwater impact from the operation of the Polk County Site will be the withdrawal of water from the Upper Floridan Aquifer for process water and cooling pond makeup. Water from the Upper Floridan Aquifer is the lowest quality of groundwater that can be used for the Polk County Site while maintaining the cooling pond as a zero discharge facility. The withdrawal of 17.5 mgd from the Upper Floridan Aquifer at ultimate site development will not adversely impact offsite legal users of groundwater and will comply with the SWFWMD consumptive use criteria for groundwater withdrawal. Ecological Resources The baseline for the ecological resources at the Polk County Site was established as the site condition that would exist following (i) mandatory reclamation under reclamation plans approved by the DEP/BOMR, and (ii) non- mandatory reclamation normally carried out by the mining companies. In the cases of Tiger Bay, which has been reclaimed and released by DEP/BOMR, and Tiger Bay East, which has revegetated naturally without reclamation, the ecological baseline was represented by the current condition of these parcels. This baseline methodology was proposed by FPC in a Plan of Study which was accepted by DEP in a Binding Written Agreement. The predominant land cover that would occur under the baseline condition at the Polk County Site would be agriculture. Approximately 70 percent of the Polk County Site, or approximately 5,678 acres, would be developed as crop land, citrus or pasture. The remaining 30 percent of the site would be reclaimed as non-agricultural uplands, wetlands and open water bodies. Tiger Bay already has been reclaimed and released by DEP/BOMR and Tiger Bay East has revegetated naturally. These two parcels represent one-fourth (524 acres) of the natural habitat under the ecological baseline condition. The quality of the baseline land cover and vegetation was established by surveying several onsite and offsite areas which have been reclaimed and released. Baseline aquatic resources at the Polk County Site consist of Tiger Bay and the aquatic resources which would have been developed under existing reclamation plans. This baseline would include open water bodies and forested wetlands in parcels SA- 11 and SA-12, and forested and herbaceous wetlands in parcel N-16. Both Estech and IMC have exceeded their mine-wide wetlands mitigation obligations even without those wetlands. The quality of the baseline open water bodies on the Polk County Site was evaluated by surveying parcel N- 16, which currently consists of open water habitat. The quality of wetlands was determined by surveying Tiger Bay, which contains wetlands that have been reclaimed and released. The baseline aquatic resources were found to have significant fluctuations of dissolved oxygen, and were characterized by encroachment of cattail, water hyacinth and other nuisance species. All of the aquatic areas sampled as representative of baseline conditions showed significant eutrophication. No DEP or SWFWMD jurisdictional wetlands currently exist onsite, within areas in which phosphate mining activities have been or will be conducted, except in the reclaimed Tiger Bay and Tiger Bay East. Baseline evaluation of threatened and endangered species, and species of special concern (listed species) was conducted by collecting information regarding regional habitat descriptions; plant species lists and ecological reports for the area; lists and ecological reports of birds, mammals, reptiles and amphibians common to the area; species checklists; reports of sightings or abundance estimates; interspecific relationships and food chains of important species; location of rare, threatened or endangered species or critical habitat for these species in the region; and occurrence of potential preexisting stresses. Information from the Florida Natural Areas Inventory and approved mine reclamation plans was reviewed. Visits were made to nearby reclaimed sites by land and low-flying helicopters. No listed plant species were found at the site or offsite study areas. Existing reclamation plans, and consequently the ecological baseline condition, do not require the planting of such species. Listed animal species which were observed at the Polk County Site and are expected under the baseline conditions include the American alligator, woodstork, southeastern kestrel, osprey, little blue heron, snowy egret and tricolored heron. The baseline conditions would provide suitable feeding habitat for these species, but only limited areas of suitable nesting habitat. Both the current condition of the site and baseline condition provide feeding habitat for the American bald eagle, however, the nesting potential for this species will be greater after the implementation of the baseline condition. Impacts to the baseline ecological resources from the construction and operation of the Polk County Site will be more than compensated by habitat creation and enhancement programs proposed by FPC. The primary impacts to the baseline ecological resources will occur when power plant facilities, such as the plant island, cooling pond, brine pond and solid waste disposal area are constructed, eliminating these parcels from the baseline ecological resources. Without development of the Polk County Site, these parcels would represent approximately 2,268 acres of viable lakes and upland and wetland habitats. FPC has proposed a total of 3,713 acres of viable wildlife habitat as part of the ultimate development of the Polk County Site. Accordingly, the available wildlife habitat after construction of the Polk County Site represents a net increase of 1,445 acres over the baseline ecological resource conditions. This increase in habitat, particularly in the buffer area, will be a net benefit for protected species. In providing more wildlife habitat than baseline conditions, FPC has agreed to certain enhancement activities that will specifically offset any impact to baseline ecological resources. These enhancement programs include habitat and wetland creation in parcels N-9B and N-13; habitat creation and offsite drainage enhancement in parcel SA-10; implementation of a wildlife habitat management plan and exotic vegetation control in parcels SA-10, N-9B and N-13; drainage enhancement to McCullough Creek and Camp Branch; and funding the acquisition of a 425 acre offsite area to serve as part of a wildlife corridor. Air Pollution Control Polk County has been designated by the U.S. Environmental Protection Agency (EPA) and DEP as an attainment area for all six criteria air pollutants. Federal and state Prevention of Significant Deterioration (PSD) regulations provide that the project will be subject to "new source review." This review generally requires that the project comply with all applicable state and federal emission limiting standards, including New Source Performance Standards (NSPS), and that Best Available Control Technology (BACT) be applied to control emissions of PSD pollutants emitted in excess of applicable PSD significant emission rates. The project will limit emission rates to levels far below NSPS requirements. For the initial 470 MW phase of the Project, BACT must be applied for the following pollutants: sulfur dioxide (SO2), nitrogen oxides (NOx), particulates (PM and PM10), volatile organic compounds (VOCs), carbon monoxide (CO), beryllium, inorganic arsenic, and benzene. For the ultimate site capacity, BACT is required for each of these pollutants, and sulfuric acid mist (H2SO4), mercury, and lead as well. BACT is defined in DEP Rule 17-212.200(16), Florida Administrative Code, as: An emission limitation, including a visible emission standard, based on the maximum degree of reduction of each pollutant emitted which the Department, on a case-by-case basis, taking into account energy, environmental and economic impacts, and other costs, determines is achievable through application of production processes and available methods, systems and techniques (including fuel cleaning or treatment or innovative fuel combustion techniques) for control of each such pollutant. The primary purpose of a BACT analysis is to minimize the allowable increases in air pollutants and thereby increase the potential for future economic growth without significantly degrading air quality. Such an analysis is intended to insure that the air emissions control systems for the project reflect the latest control technologies used in a particular industry and is to take into consideration existing and future air quality in the vicinity of the project. The BACT analysis for the project therefore evaluated technical, economic, and environmental considerations of available control technologies and examined BACT determinations for other similar facilities across the United States. For the first 470 MW of NGCC units, BACT for SO2 emissions from the CTs is the use of natural gas as the primary fuel and the use of low sulfur oil for a limited number of hours per year. For the first 470 MW of NGCC units, BACT for CO, VOCs, PM, beryllium, arsenic, and benzene emissions from the CTs is efficient design and operation of the CTs, the inherent quality of natural gas (the primary fuel), and a limitation on the annual use of fuel oil. For the first 470 MW of combined cycle units, BACT for NOx emissions from the CTs is the use of advanced dry low NOx combustors capable of achieving emissions of 12 parts per million by volume dry (ppmvd) at 15 percent oxygen when burning natural gas, water/steam injection to achieve 42 ppmvd at 15 percent oxygen when burning fuel oil, and limited annual fuel oil use. For the first 470 MW of NGCC units, the DEP staff initially proposed BACT for NOx emissions from the CTs as 9 ppmvd at 15 percent oxygen when burning natural gas, using dry low NOx combustor technology. However, after careful consideration, it was determined that, because of the lack of proven technology to achieve such emission rate, it would be more appropriate to establish BACT at 73 lb/hour/CT (24-hour average, based on 12 ppmvd at 15 percent oxygen and 59o F) using dry low NOx combustor technology and to require FPC to make every practicable effort to achieve the lowest possible NOx emission rate with those CTs when firing natural gas. FPC also is required to conduct an engineering study to determine the lowest emission rate consistently achievable with a reasonable operating margin taking into account long-term performance expectations and assuming good operating and maintenance practices. Based on the results of that study, DEP may adjust the NOx emission limit downward, but not lower than 55 lb/hour/CT (24-hour average, based on 9 ppmvd at 15 percent oxygen and 59o F.). For the 99 MBtu/hour auxiliary boiler that is part of the initial phase of the project, BACT for NOx emissions is low NOx burners, limited annual fuel oil use, and limited hours of annual operation. BACT for NOx emissions from the 1300 kW diesel generator is combustion timing retardation with limited hours of annual operation. For the 99 MBtu/hour auxiliary boiler and the diesel generator as part of the initial phase of the project, BACT for CO, VOC, SO2, PM, benzene, beryllium, and arsenic emissions consists of good combustion controls, the inherent quality of the fuels burned, the use of low-sulfur fuel oil, and limited hours of operation. For the fuel oil storage tank as part of the initial phase of the project, BACT is submerged filling of the tank. For the coal gasification and other facilities to be built during later phases of the project, a preliminary BACT review was undertaken by FPC to support the demonstration that the Polk County Site has the ultimate capacity and resources available to support the full phased project. Air Quality Impact Analysis Air emissions from the project also must comply with Ambient Air Quality Standards for six criteria pollutants and Prevention of Significant Deterioration increments for three pollutants. Polk County and the contiguous counties are classified as Class II areas for PSD purposes; the nearest Class I area is the Chassahowitzka National Wilderness Area, located approximately 120 km. from the Site. An air quality analysis, undertaken in accordance with monitoring and computer modeling procedures approved in advance by EPA and DEP, demonstrated that the project at ultimate capacity utilizing worst-case assumptions will comply with all state and federal ambient air quality standards as well as PSD Class I and II increments. For nitrogen dioxide, sulfur dioxide and particulate matter, air quality modeling was based on conservative assumptions, including background concentrations based upon the highest long- term and second highest short-term measured values (established through an onsite one-year air quality monitoring program and regional data), existing major sources at their maximum emissions, the estimated maximum emissions from certain other proposed projects, and the impacts of the proposed FPC project at ultimate site capacity. For other pollutants, detailed analyses were not performed because offsite impacts were predicted to be insignificant. Impacts of the project's estimated emissions of certain hazardous air pollutants (antimony, arsenic, barium, beryllium, benzene, boron, cadmium, calcium, chromium, cobalt, copper, formaldehyde, magnesium, manganese, nickel, selenium, vanadium, and zinc) at ultimate capacity were compared to the DEP draft no-threat levels under DEP's draft "Air Toxics Permitting Strategy." All pollutants except arsenic were projected to be below the corresponding draft no- threat level. Because of the conservatism of DEP's draft no-threat levels, it was concluded that arsenic impacts would not pose a significant health risk to the population in the surrounding area. Impacts on vegetation, soils, and wildlife in both the site area and the vicinity of the Chassahowitzka National Wilderness Area, the nearest PSD Class I area, will be minimal. Visibility in the vicinity of the Chassahowitzka National Wilderness Area will not be impaired significantly by the project's emissions. Air quality impacts from commercial, industrial, and residential growth induced by the project are expected to be small and well-distributed throughout the area. Impacts from the initial phase of the Project (470 MW) will comply with all State and federal ambient air quality standards as well as PSD Class I and II increments. The impacts from the initial phase of the Project are also well below the draft no-threat levels. The initial phase of the Project will not significantly impair visibility in the vicinity of the Chassahowitzka National Wilderness Area, and the impact on vegetation, soils, and wildlife in both the site area and the vicinity of the Chassahowitzka National Wilderness Area will be minimal. The air quality impacts due to commercial, industrial, and residential growth from the initial phase of the Project will be small, and are not expected to impact air quality. Land Use Planning/Socioeconomic Impacts of Construction and Operation The proposed site is an appropriate location for the Polk County Site project. The Polk County Site has adequate access to highway and rail networks, including CR 555, a major collector road, and the CSX railroad. The Polk County Site is located away from major residential areas in a location already heavily disturbed by mining activity. The site is located in reasonable proximity to major metropolitan areas that can supply an adequate work force for construction. Development of the Polk County Site in a mined-out phosphate area is a beneficial use of land and will provide an economic benefit for Polk County. The Polk County Site also is close to existing facilities, such as existing transmission line corridors and reclaimed water facilities, which will benefit the operation of the site while minimizing the impact of the project. The linear facilities associated with the Polk County Site are sited in appropriate locations. The 230-kV transmission line upgrade, reclaimed water pipeline and backup natural gas pipeline corridors: (i) are located adjacent to other linear facilities, such as existing roads and transmission lines, (ii) avoid major residential areas, and (iii) minimally disrupt existing land uses. The Polk County Site is compatible with the State Comprehensive Plan, the CFRPC Regional Policy Plan, and will meet the requirements of the Polk County Conditional Use Permit. The portion of the backup natural gas pipeline located in Hillsborough County is consistent with the Hillsborough County Comprehensive Plan and the policies of the TBRPC Regional Policy Plan. Construction of the Polk County Site will occur over an approximately 25-year period beginning in 1994. If the Polk County Site is developed only for NGCC capacity, construction employment will average 153 jobs per year with a peak employment of 350. The average annual payroll for construction of the Polk County Site on all NGCC is expected to be $7.1 million per year. If 1,000 MW of NGCC and 2,000 MW of CGCC units are built at the Polk County Site, peak construction employment will be 1,000 with an average annual construction employment of 315 over the approximate 25-year period. Average annual payroll under this scenario would be $14.6 million per year. Indirect jobs created as a result of buildout of the Polk County Site will average 231 jobs for all NGCC and 477 jobs if 2,000 MW of CGCC is added to the Polk County Site. After completion of the construction of the Polk County Site at ultimate capacity, 110 permanent direct jobs will be created if the site uses all NGCC and 410 jobs will be created if coal gasification is added to the Polk County Site. The operation of the Polk County Site will have a multiplier effect on the Polk County economy. The all NGCC scenario will create 272 indirect jobs and the Case A' scenario with CGCC will create 1,013 indirect jobs. After buildout, property taxes generated by the Polk County Site are estimated to be $24.3 million per year for the all NGCC scenario and $37.4 million per year if CGCC capacity is constructed at the site. Noise Impacts The ambient noise, or baseline noise condition at the Polk County Site was measured in five locations. These measurements show that the baseline noise condition for the site ranges between 30 dBA and 65 dBA at the nearest residential location. The higher noise levels are caused by truck traffic associated with the phosphate mining industry. Noise impacts from construction will be loudest during initial site preparation and steel erection stages. Earth moving equipment will produce noise levels of 45 to 50 dBA at the nearest residence in Homeland. During final phases of construction, steam blowout activity to clean steam lines will produce short duration noise levels of 69 dBA at the nearest residence. This activity will take place only during daylight hours. Noise levels from the operation of the Polk County Site were calculated using a computer program specifically designed for assessing noise impacts associated with power plant operation. The highest predicted continuous noise level will be 41 dBA at several houses 2.9 miles south of the site and 47 dBA at the nearest church. Noise impacts from fuel delivery trucks and coal trains will not significantly increase the noise levels over existing conditions. The continuous noise level from the operation of the Polk County Site at the nearest residence or church will be below the 55 dBA level recommended by the U.S. Environmental Protection Agency. Traffic Traffic analyses were made for impacts to highway traffic which will result from the construction and operation of the Polk County Site. These analyses included impacts at rail crossings caused by the delivery of coal to the Polk County Site under the Case A' scenario. A highway traffic analysis was made to determine if the existing roadway network in the vicinity of the Polk County Site would operate at acceptable levels of service based upon increased volumes of traffic associated with the construction and operation employment at the Polk County Site. Methodologies for evaluating traffic impact complied with Polk County, FDOT and CFRPC criteria. County roads were evaluated using Polk County criteria and state roads were evaluated using both Polk County and FDOT criteria. Traffic volumes were evaluated for peak construction traffic in 2010 and full plant operations, estimated in 2018. The traffic evaluation included analysis of existing traffic conditions, increased traffic volume associated with growth in the area not associated with the Polk County Site, and increased traffic associated with construction and operation employment at the Polk County Site. During peak construction employment under the Case A' scenario, 1,000 employees are expected at the Polk County Site. Under this scenario, the expected trip generation of the Polk County Site is expected to be 1,792 trips per day, with a morning peak of 717 trips and an afternoon peak of 717 trips. Based on this analysis, all roadways are expected to operate at acceptable levels of service with currently planned improvements to the roadways. Intersection levels of service were found acceptable for 7 out of 11 intersections. FPC has recommended improvements to four intersections at U.S. 98 and SR 60A, SR 60 and CR 555, SR 37 and CR 640, and CR 555 and CR 640 at specified traffic levels. Peak operation employment under the Case A' scenario is expected to be 410 employees in 2018. Based upon this employment figure, the expected trip generation of the Polk County Site is 964 trips per day with a morning peak of 195 trips and an afternoon peak of 154 trips. At peak operation employment, all roadways evaluated were found to operate at acceptable levels of service. All intersections, except the intersection at SR 60 and CR 555, were found to operate at acceptable levels. FPC has recommended a protected/permissive westbound left turn lane at this intersection. With FPC's recommended improvements, which have been incorporated as conditions of certification, and those improvements currently planned by FDOT, the existing roadway network will meet Polk County and FDOT approved levels of service at peak employment during the construction and operation of the Polk County Site to its ultimate capacity. In addition to the highway traffic impact analysis, FPC evaluated the impact on rail/highway crossings from the transportation of coal by rail under the Case A' scenario. It was assumed that all coal for the Polk County Site will be delivered by rail over existing CSX transportation lines. It is expected that at full operation two 90-car trains per day will be required for the delivery of coal, resulting in four train trips per day. It was also assumed that trains will travel at speeds averaging 35 to 45 miles per hour. Evaluation of the impacts at rail crossings found an increase of .5 second per vehicle per day at urban rail crossings and .3 second per vehicle per day at rural rail crossings. Based on the 1985 Highway Capacity Manual, the total delay at rail crossing intersections caused by the increased train traffic to and from the Polk County Site will not cause a significant delay and the rail crossing intersections will maintain level of service A. Archaeological and Historic Sites The Florida Department of State, Division of Historical Resources, has stated that because of the location of the Polk County Site, it is unlikely that any significant archaeological or historical sites will be affected. Mandatory Reclamation of Mining Parcels The Polk County Site is comprised of phosphate mining parcels, portions of which are subject to mandatory reclamation under the jurisdiction of DEP/BOMR. The mandatory mining parcels are currently owned by Estech, IMC, and USAC. FPC has entered into stipulations with each mining company agreeing to reclamation of the mandatory mining parcels in accordance with the conditions of certification proposed by DEP/BOMR. In those conditions, DEP has proposed to incorporate the reclamation conceptual plan modifications included in Appendix 10.9 of the SCA into the certification proceeding for the Polk County Site and has redesignated those conceptual plan modifications as EST-SC-CPH and IMC-NP- FPC. The portions of the site which will be developed by FPC will be released from mandatory reclamation requirements when FPC purchases the Polk County Site. Variances FPC has requested variances from certain reclamation standards set forth in Rule 16C-16.0051, Florida Administrative Code, which will be necessary until the affected mining parcels on the Polk County Site are released from reclamation. FPC has requested a variance from Rule 16C-16.0051(5)(a), which requires artificial water bodies to have an annual zone of fluctuation, and Rule 16C-16.0051(5)(b), which requires submerged vegetation and fish bedding in artificially-created water bodies. The criteria in these rules are inappropriate for a cooling pond, because it is an industrial wastewater treatment facility which cannot be efficiently or safely operated with fluctuating water levels and aquatic vegetation zones. With regard to the construction of dams for the cooling pond, brine pond and solid waste disposal areas, FPC will need a variance from Rule 16C-16.0051(2)(a), which requires a 4:1 slope for dam embankments and Rule 16C-16.0051(9)(b) and (c), which requires vegetation of upland areas, which may include dam embankments. Dams for the cooling pond, brine pond and solid waste disposal areas will have steeper slopes and the interiors of the dams will be concrete blanket revetments, synthetic liners or solid waste consistent with the industrial purposes for which these facilities have been constructed. Access to these areas will be controlled to prevent any potential safety hazard. Finally, FPC will need a variance from Rule 16C-16.0051(11)(b)(4), which requires reclamation to be completed within two years after mining operations are completed. Construction of the Polk County Site requires extensive dewatering and earthwork which cannot be completed within this timeframe. Applications for variances from mining reclamation criteria were included in Appendix 10.9 of the SCA and have been incorporated into the certification proceeding for the Polk County Site. DEP has redesignated these variance applications as EST-SC-FPC-V and IMC-NP-FPC-V. These variances are appropriate and should be granted. Agency Positions and Stipulations The Department of Environmental Protection, Southwest Florida Water Management District, and Polk County have recommended certification for the construction and operation of the initial 470 MW of natural gas combined cycle generating capacity and have recommended the determination that the Polk County Site has the ultimate capacity for 3,000 MW of natural gas and coal gas combined cycle generating capacity, subject to appropriate conditions of certification. No other state, regional or local agency that is a party to the certification proceeding has recommended denial of the certification for the construction of the initial 470 MW of generating capacity or determination of ultimate site capacity. Several agencies which expressed initial concern regarding certification of the Polk County Site have resolved those concerns with FPC and have entered into stipulations with FPC as discussed below. The Florida Department of Transportation, the Game and Fresh Water Fish Commission, and the Department of Community Affairs have entered into stipulations with FPC recommending certification of the Polk County Site and a determination that the Polk County Site has the ultimate site capacity to support 3,000 MW of NGCC and CGCC generating capacity subject to proposed conditions of certification. Hillsborough County, the Environmental Protection Commission of Hillsborough County, and the Tampa Port Authority have entered into a stipulation and agreement with FPC recommending certification of the backup natural gas pipeline corridor subject to proposed conditions of certification. FPC and the agency parties have agreed on a set of conditions of certification for the Polk County Site. Those conditions are attached as Appendix A to this Recommended Order.
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that: Florida Power Corporation be granted certification pursuant to Chapter 403, Part II, Florida Statutes, for the location, construction and operation of 470 MW of combined cycle generating capacity as proposed in the Site Certification Application and in accordance with the attached Conditions of Certification. Florida Power Corporation's Polk County Site be certified for an ultimate site capacity of 3,000 MW fueled by coal gas, natural gas, and fuel oil subject to supplemental application review pursuant to 403.517, Florida Statutes, and Rule 17-17.231, Florida Administrative Code, and the attached Conditions of Certification. A zone of discharge be granted in accordance with the attached Conditions of Certification. The conceptual plan modifications (EST-SC-CPH and IMC-NP-FPC) for the mandatory phosphate mining reclamation plans be granted subject to the attached Conditions of Certification. The variances from reclamation standards (EST-SC-FPC-V and IMC-NP-FPC- V) as described herein be granted subject to the attached Conditions of Certification. DONE AND ENTERED this 3rd day of December, 1993, in Tallahassee, Florida. DIANE K. KIESLING, Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 3rd day of December, 1993. APPENDIX TO RECOMMENDED ORDER, CASE NO. 92-5308EPP RECOMMENDED CONDITIONS OF CERTIFICATION * * NOTE: 114 page Recommended Conditions of Certification plus attachments is available for review in the Division's Clerk's Office. COPIES FURNISHED: Gary P. Sams Richard W. Moore Attorneys at Law Hopping Boyd Green & Sams Post Office Box 6526 Tallahassee, Florida 32314-6526 Representing Applicant Pamela I. Smith Corporate Counsel Florida Power Corporation Post Office Box 14042 St. Petersburg, Florida 33733-4042 Richard Donelan Assistant General Counsel Department of Environmental Regulation 2600 Blair Stone Road, Room 654 Tallahassee, Florida 32399-2400 Representing DER Hamilton S. Oven, Jr. Office of Siting Coordination Division of Air Resources Mgmt. Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Lucky T. Osho Karen Brodeen Assistant General Counsels Department of Community Affairs 2740 Centerview Drive Tallahassee, Florida 32399-2100 Representing DCA Michael Palecki, Chief Bureau of Electric & Gas Florida Public Service Commission 101 East Gaines Street Tallahassee, Florida 32399-0850 Representing PSC M. B. Adelson, Assistant General Counsel Department of Natural Resources 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Representing DNR Carolyn S. Holifield, Chief Chief, Administrative Law Section Department of Transportation 605 Suwanee Street, Mail Station 58 Tallahassee, Florida 32399-0458 Representing DOT Doug Leonard, Executive Director Ralph Artigliere, Attorney at Law Central Florida Regional Planning Council 409 East Davidson Street Bartow, Florida 33830 Representing CFRPC Julia Greene, Executive Director Tampa Bay Regional Planning Council 9455 Koger Boulevard St. Petersburg, Florida 33702 Representing Tampa Bay Regional Planning Council John J. Dingfelder Assistant County Attorney Hillsborough County Post Office Box 1110 Tampa, Florida 33601-1110 Representing Hillsborough County Mark Carpanini Attorney at Law Office of County Attorney Post Office Box 60 Bartow, Florida 33830-0060 Representing Polk County Martin D. Hernandez Richard Tschantz Assistant General Counsels Southwest Florida Water Management District 2370 Broad Street Brooksville, Florida 34609-6899 Representing SWFWMD James Antista, General Counsel Florida Game and Fresh Water Fish Commission Bryant Building 620 South Meridian Street Tallahassee, Florida 32399-1600 Representing GFWFC Sara M. Fotopulos Chief Counsel Environmental Protection Commission of Hillsborough County 1900 Ninth Avenue Tampa, Florida 33605 Representing EPCHC Joseph L. Valenti, Director Tampa Port Authority Post Office Box 2192 Tampa, Florida 33601 Representing Tampa Port Authority Board of Trustees of the Internal Improvement Trust Fund Don E. Duden, Acting Executive Director Department of Natural Resources 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Representing the Trustees Honorable Lawton Chiles Governor State of Florida The Capitol Tallahassee, Florida 32399 Honorable Robert A. Butterworth Attorney General State of Florida The Capitol Tallahassee, Florida 32399-1050 Honorable Bob Crawford Commissioner of Agriculture State of Florida The Capitol Tallahassee, Florida 32399-0810 Honorable Betty Castor Commissioner of Education State of Florida The Capitol Tallahassee, Florida 32399 Honorable Jim Smith Secretary of State State of Florida The Capitol, PL-02 Tallahassee, Florida 32399-0250 Honorable Tom Gallagher Treasurer and Insurance Commissioner State of Florida The Capitol Tallahassee, Florida 32399-0300 Honorable Gerald A. Lewis Comptroller State of Florida The Capitol, Plaza Level Tallahassee, Florida 32399-0350
The Issue Whether the application of Getty Oil Company for a permit to conduct dredge and fill activities by the construction of an oyster shell platform and by dredging (drilling) in East Bay, Santa Rosa County, should be approved, pursuant to Chapters 253 and 403, F.S. Whether the application of Getty Oil Company for a variance from Rule 17-4.28(8)(a), F.A.C., to construct a shell foundation pad and to drill one natural gas exploratory well in East Bay, Santa Rosa County, should be approved, pursuant to Chapter 403, F.S. Whether the application of Getty Oil Company for a permit for natural gas flare construction should be approved, pursuant to Chapter 403, F.S. Whether the application of Getty Oil Company for a drilling permit should be approved, pursuant to Chapter 377, F.S. These proceedings stem from Getty Oil Company's intent to erect a structure and drill a test well in East Bay, Santa Rosa County, for the purpose of natural gas exploration. The waters of East Bay are Class II, approved for shellfish harvesting. Getty holds leasehold rights for drilling at the proposed site under an assignment of a lease granted by the Trustees of the Internal Improvement Trust Fund in 1968. DER issued Notices of Intent to grant Getty's three applications, subject to specific conditions, as follows: Request for Variance By letter of April 3, 1980, the DER Director of Division of Environmental Permitting issued its Notice of Intent to grant a variance from Section 17- 4.28(8)(a), Florida Administrative Code, pursuant to Section 403.201(1)(a)(c) Florida Statutes, to permit the requested dredge and fill activities in an area approved for shellfish harvesting by the Department of Health and Rehabilitative Services. Dredge and Fill permit By letter of April 3, 1980, the DER manager of the Northwest District issued Notice of Intent to issue a dredge and fill permit for the construction of the exploratory gas drilling platform provided that the applicant obtained a variance from the requirements of Sections 17-4.28(8)(a), Florida Administrative Code. Natural Gas Flare Construction Permit By letter of June 16, 1980, the DER manager of the Northwest District issued Notice of Intent to issue a permit for natural gas flare construction at the East Bay test site in Santa Rosa County. DNR issued the following Notices of Intent regarding the Chapter 377 drilling permit: By letter of June 18, 1980, as amended by letter of June 23, 1980, the Executive Director of the Department of Natural Resources issued Notice of Intent to recommend denial of Getty's application for a permit to drill in East Bay for the reason that Section 377.242, Florida Statutes, prohibits the construction of structures for the production of oil, gas and other petroleum products on submerged lands within the lease area. However, by further order of the Executive Director, dated duly 28, 1980, Notice of Intent was issued to recommend approval of the drilling permit application, subject to specified conditions in the event that the legal opinion expressed in his prior letters concerning the prohibition against drilling as set forth in Section 377.242, Florida Statutes, was found to be incorrect. Although the DER cases were originally scheduled for hearing in August, 1980, the consolidation of the DNR cases resulted in the granting of a motion for a continuance of the hearing until November, 1980. At the commencement of the hearing, the parties announced that they had arrived at a stipulated settlement and that all issues raised in the consolidated cases were, with two exceptions, withdrawn by the parties with respect to the three permit applications and the variance application. The two issues reserved by the Stipulation involved the application of Section 377.242(1), Florida Statutes, with respect to the requested drilling permit from the Department of Natural Resources. The Stipulation was accepted by the Hearing Officer as sufficiently comprehensive to meet the requirements of pertinent statutes and regulations with regard to the permits under consideration. Paragraph VI of the Stipulation provides that paragraphs II and IV of the Stipulation shall be specifically incorporated into the agency permits or variance to which those paragraphs refer. In view of the agreed resolution of the two DER permit applications, a hearing on those matters became unnecessary. However, as to the application for variance, subsection 403.201(2), Florida Statutes, mandates that the Department hold a hearing on each application for variance. Inasmuch as the parties to the proceedings had resolved all factual and legal questions in their Stipulation, the only remaining purpose for a hearing was to permit public participation. Accordingly, twelve public witnesses testified at the hearing (Hearing Officer's Exhibit 1), four of whom submitted documentary materials (Exhibits 1-4). These included a petition signed by local area citizens in support of the project, a favorable recommendation by the Pensacola Area Chamber of Commerce, a statement from the League of Women Voters from the Pensacola Bay Area expressing concern for preservation and protection of estuaries and wetlands, and various publications submitted by one witness. After the receipt of public testimony, the hearing was continued until November 24, 1980 for presentation of evidence concerning the two remaining issues reserved by the parties in their Stipulation. Due to the fact that the DER was not a party to the matters remaining for consideration, its representative did not participate in the further proceedings. During the hearing sessions on November 12- 13, 1980, twenty eight exhibits were provisionally received in evidence. (Hearing Officer's Exhibit 2) . Eight additional exhibits were received in evidence during the session on November 24-25, 1980. (Hearing Officer's Exhibit 2) By Recommended Order, dated December 15, 1980, the Hearing Officer recommended to DER that the Stipulation of the parties be accepted, and that the requested DER permits and variance be issued in accordance with the terms thereof. The two issues reserved by the Stipulation involving the application of Section 377.242(1), Florida Statutes, are as follows: Whether Section 377.242(1), Florida Statutes, prohibits the proposed drilling on submerged lands located in East Bay. Whether Section 377.242(1), Florida Statutes, can be constitutionally applied to prohibit Getty from conducting the proposed drilling on submerged lands located in East Bay. Evidence was received at the hearing as to whether Getty Oil Company is authorized by the statutory provision in question to drill at the proposed site. As to the constitutional issue, Getty was permitted to proffer testimony to preserve such issue for any future judicial determination. The following findings of fact are restricted accordingly.
Findings Of Fact Getty Oil Company proposes to drill a hydrocarbon exploration well pursuant to State Drilling Lease No. 2338. The lease was issued by the Trustees of the Internal Improvement Trust Fund of the State of Florida on July 9, 1968, to J. Melvin Young, Arden A. Anderson, and Philip D. Beall. Getty purchased the lease from the original lessees on March 10, 1970. The lease grants the right to explore for and produce oil and gas from the state-owned submerged water bottoms of East Bay, Blackwater Bay, and that portion of Escambia Bay lying in Santa Rosa County, a combined total of 47,932 acres. The proposed well would be drilled from submerged lands located in approximately the center of East Bay to a depth of approximately 17,800 feet. (Testimony of Anderson, Exhibits 6, 27) The well site will be located some 2.7 miles from the nearest shore and about six miles from the Gulf of Mexico. The site is not within one mile from the seaward boundary of the Yellow River Marsh Aquatic Preserve, the Fort Pickens State Park Aquatic Preserve, or the Gulf Islands National Seashore. East Bay is an estuary which is part of an estuarine "system" in the immediately surrounding area of Pensacola. An estuary is an area that is a buffer zone between the open ocean where the salinity is equal to 35 parts per thousand, and the fresh water river areas which drain into the system. The fresh water runoff carries nutrients into the system which in turn result in productivity of plants and organisms, including fish, shrimp, oysters, and other shellfish of various types. Estuarine systems are therefore one of the most productive types of ecosystems. East Bay is one of the best parts of the estuarine system from the standpoint of both water quality and general health of the system. Although during the major periods of river drainage in the winter and spring months, low water salinity exists on the surface of East Bay, the bay is not considered to be a fresh water lake, river or stream from an ecological standpoint. (Testimony of Herbert, Livingston, Exhibits 6, 15, 26, 29-32) The coastline of Florida in the vicinity of East Bay coincides with the seaward boundary of Santa Rosa Island, a barrier island, and extends across the mouth of the entrance to Escambia Bay. East Bay is connected to Escambia Bay, but does not connect directly to the Gulf of Mexico. (Stipulation, Exhibits 29, 31 and 32) Based on seismic data obtained from a 1970 survey of the Getty Oil Company's leased area, including East Bay, the only possible structure where hydrocarbons could be located beneath submerged lands is one covering 2,860 acres or approximately 4 1/2 square miles. The proposed well site is at the top center of the structure, which extends some 17,800 feet below the surface of the submerged land. There is no evidence that there are commercially recoverable deposits of salt, brines, or sulphur under the lands of the leasehold area. Hydrocarbon accumulations tend to occur along the crest of regional arches. The crest of the Santa Rosa Arch has been projected to be underneath the East Bay area. (Testimony of McCarthy, Greenwell, Exhibits 34-35) Studies conducted by Getty Oil Company to determine the advisability of drilling at the proposed site led it to the conclusion that there is one chance in twelve that hydrocarbons would be present in the target structure in commercially productive amounts. These studies also produced an estimate that Getty would accrue about $537,000,000 before state and federal income taxes if it vertically drilled four producing and one non-producing wells in the area. (Testimony of Greenwell) Directional well drilling is performed by the oil industry to maximum lateral deviations of 10,000 to 12,000 feet, depending upon varying conditions at the site. In such instances, an angle is formed at periodic intervals which eventually deviates sufficiently to reach the target structure. Straight-line slant drilling is only feasible in cases of shallow wells. Directional drilling creates varying problems based on the depth and lateral deviation required in a particular place. The "doglegs" required in creating the necessary angles pose extreme difficulties in removing cuttings from the drill hole. The angles created in the process produce tremendous torque and cause pipe "fatigue." Drill collars are subject to sticking and, at extreme depths, it is doubtful if turning of the pipe can be achieved. Such a method of drilling makes it difficult to control direction, particularly at great depths. Additionally, at extreme depths where the temperature is some 325 degrees, the rubber material of "down-hole" motors is melted. (Testimony of Porterfield, Moore) In order for Getty Oil Company to directionally drill from land to the target structure under East Bay, it would be necessary to commence drilling on land approximately 3.3 miles from the bay site at a point about 1 1/4 miles due north of White Point. Drilling at that location would require a 50 percent lateral deviation of some 17,500 feet and a total drilling distance of some 25,000 feet. Such a distance has never been attempted in the history of directional drilling and is considered by experts in the field to be virtually impossible from a technological standpoint. Such a well would require that 2 1/2 degree angles be formed every 100 feet. These bends in the well hole through which the pipe must be extended and bent would create extremely severe pipe failure problems and exacerbate the other traditional difficulties encountered in directional drilling. Further, the cost of directional drilling at the Getty site would make such an undertaking economically undesirable even if it were technically possible. In view of all the considerations, Getty Oil Company does not consider directional drilling a viable alternative to vertical drilling, and therefore would not undertake drilling by such a method. Getty does not own or hold property interests in any dry-land areas near the shore of East Bay. (Porterfield, Moore, Englert) Prior to 1972, the Department of Natural Resources issued permits to drill in submerged lands of the state. Subsequent to the 1972 enactment of Section 377.242(1), Florida Statutes, no such permits have been issued and the pending application of Getty Oil Company is the only one which has been received by the Department since that time. Based on prior policy, the Chief of the Department's Bureau of Geology recommended to the Executive Director that Getty's application be approved. His reason for such recommendation was that he had not been aware that there was a variation in the 1972 statute and the Department's prior policy. Dr. Elton J. Gissendanner, Executive Director, however, determined that the statutory provision prohibited the placement of structures for the purpose of producing oil or gas anywhere in submerged lands in the state within a mile seaward from the coastline, which he considered to be located at the seaward border of Santa Rosa Island. He interpreted additional language in the statutory provision (which prohibited the issuance of a drilling permit within one mile inland from the coastline unless estuaries, beaches and shore area were adequately protected in the event of accident) to refer to uplands, and that therefore unrestricted drilling on land could only occur more than a mile from the coastline. In this manner, he concluded that the legislature intended to protect all estuaries of the state. He views his decision to constitute a proposed departmental policy which would require ratification by the Governor and Cabinet as head of the Department. However, no rules have been issued in implementation of the statutory provision. Based on his interpretation of the statute, the initial letter of intent to deny the requested permit was issued on June 18, 1980, as amended by his letter of June 23, 1980. By his further letter of July 28, 1980, the Executive Director informed Getty Oil Company that he had been directed by the Governor and Cabinet to issue a Notice of Intent to recommend final agency action concerning the merits of the application in the event that his legal position was overruled. The letter stated that pursuant to that mandate, and after review of the application, he intended to recommend approval of a permit to drill the requested test well in East Bay for the reason that the application complied with all criteria set forth in Chapter 16C-2, Florida Administrative Code. Certain conditions were stated in the letter to which any permit would be subject. These conditions were the subject of tide later stipulation between the parties at the commencement of the final hearing in these proceedings. The statutory interpretation of the Executive Director was confirmed in a later departmental legal opinion. (Testimony of Henry, Gissendanner, Exhibits 15, 20, 36) Various legislative materials, including bills, committee reports, and transcripts of committee meetings which primarily were preliminary to or contemporaneous with the passage of the legislation that became Section 377.242(1), F.S., were admitted in evidence (Exhibit 33a-p). A post-hearing Motion of Getty Oil Company to supplement the record with additional legislative materials was granted in part by the official recognition of a Report of the House Committee on Environmental pollution Control (Exhibit 33q). A further post-hearing Motion of United Citizens Against pollution, Inc. to supplement the record with further pertinent legislative materials was similarly granted (Exhibit 33r, s).
The Issue This proceeding is for the purpose of resolving a territorial dispute regarding the extension of gas service to areas of The Villages of Sumter Lake (“The Villages”) in Sumter County, Florida, pursuant to section 366.04(3)(b), Florida Statutes, and Florida Administrative Code Rule 25-7.0472; and whether a Natural Gas System Construction, Purchase, and Sale Agreement (“Agreement”) between the City of Leesburg (“Leesburg”) and South Sumter Gas Company (“SSGC”) creates a “hybrid” public utility subject to ratemaking oversight by the Public Service Commission (“Commission”).
Findings Of Fact The Parties and Stipulated Issues PGS is a natural gas local distribution company providing sales and transportation delivery of natural gas throughout many areas of the State of Florida, including portions of Sumter County. PGS is the largest natural gas provider in Florida with approximately 390,000 customers, over 600 full-time employees, and the same number of construction contract crews. PGS’s system consists of approximately 19,000 miles of distribution mains throughout Florida. PGS operates systems in areas that are very rural and areas that are densely populated. PGS currently serves more than 45,000 customers in Sumter and Marion counties. PGS is an investor-owned “natural gas utility,” as defined in section 366.04(3)(c), and is subject to the Commission’s statutory jurisdiction to resolve territorial disputes. Leesburg is a municipality in central Florida with a population of approximately 25,000 within the city limits, and a broader metropolitan service area (“MSA”) population of about 50,000. Leesburg provides natural gas service in portions of Lake and Sumter counties. Leesburg is a “natural gas utility” as defined in section 366.04(3)(c). Leesburg has provided natural gas service to its customers since 1959, and currently serves about 14,000 residential, commercial, and industrial customers both within and outside its city limits via a current system of approximately 276 miles of distribution lines. Leesburg is subject to the Commission’s statutory jurisdiction to resolve territorial disputes. SSGC is a Florida limited liability company and an operating division of The Villages. SSGC is the entity through which The Villages has entered into a written contract with Leesburg authorizing Leesburg to supply natural gas services to, initially, the Bigham developments. The issues of cost of capital and amortization and depreciation are not applicable to this dispute. The Dispute A territorial dispute is a disagreement over which natural gas utility will serve a particular geographic area. In this case, the area in dispute is that encompassed by the Bigham developments. PGS argued that the dispute should be expanded to include areas not subject to current development, but that are within the scope of anticipated Villages expansion. The extension of this territorial dispute beyond the Bigham developments is not warranted or necessary, and would have the effect of establishing a territorial boundary in favor of one of the parties. As a result of the Agreement to be discussed herein, SSGC has constructed residential gas infrastucture within Bigham, and has conveyed that infrastructure to Leesburg. Leesburg supplies natural gas to Bigham, bills and collects for gas service, and is responsible for upkeep, maintenance, and repair of the gas system. The question for disposition in this proceeding is whether service to Bigham is being lawfully provided by Leesburg pursuant to the standards applicable to territorial disputes. Natural Gas Regulation PGS is an investor-owned public utility. It is subject to the regulatory jurisdiction of the Commission with regard to rates and service. Its profits and return on equity are likewise subject to regulation. Leesburg is a municipal natural gas utility. The Commission does not regulate, or require the reporting of municipal natural gas utility rates, conditions of service, rate-setting, or the billing, collection, or distribution of revenues. The evidence suggests that the reason for the “hands- off” approach to municipal natural gas utilities is due to the ability of municipal voters to self-regulate at the ballot box. PGS argues that customers in The Villages, as is the case with any customer outside of the Leesburg city limits, do not have any direct say in how Leesburg sets rates and terms of service.1/ That may be so, but the Legislature’s approach to the administration and operation of municipal natural gas utilities, with the exception of safety reporting and territorial disputes, is a matter of legislative policy that is not subject to the authority of the undersigned. History of The Villages The Villages is a series of planned residential areas developed under common ownership and development. Its communities are age-restricted, limited to persons age 55 and older. It has been the fastest growing MSA for medium-sized and up communities for the past five years. The Villages started in the 1970s as a mobile home community known as Orange Blossom Gardens in Lake County. That community proved to be successful, and the concept was expanded in the 1980s to include developments with golf courses and clubhouses. Residents began to customize their mobile homes to the point at which the investment in those homes rivaled the cost of site-built homes. In the 1990s, The Villages went to site-built home developments. By then, one of the two original developers had sold his interest to the other, who proceeded to bring his son into the business. They decided that their approach of building homes should be more akin to traditional development patterns in which growth emanates from a central hub. Thus, in 1994, the Spanish Springs Town Center was built, with an entertainment hub surrounded by shopping and amenities. It was a success. By 2000, The Villages had extended southward to County Road (“CR”) 466, and a second town center, Lake Sumter Landing, was constructed. The following years, to the present, saw The Villages continue its southward expansion to State Road (“SR”) 44, where the Brownwood Town Center was constructed, and then to its southernmost communities of Fenney, Bigham North, Bigham West, and Bigham East, which center on the intersection of CR 468 and CR 501. The Villages currently constructs between 200 and 260 residential houses per month. Contractors are on a computerized schedule by which all tasks involved in the construction of the home are set forth in detail. The schedule was described, aptly, as rigorous. A delay by any contractor in the completion of the performance of its task results in a cascading delay for following contractors. Gas Service in the Area Gas mains are generally “arterial” in nature, with relatively large distribution mains operating at high distribution pressure extending outward from a connection to an interstate or intrastate transmission line through a gate station. Smaller mains then “pick up” growth along the line as it develops, with lower pressure service lines completing the system. In 1994, Leesburg constructed a gas supply main from the terminus of its existing facility at the Lake County/Sumter County line along CR 470 to the Coleman Federal Prison. In August 2009, PGS was granted a non-exclusive franchise by the City of Wildwood to provide natural gas service to Wildwood. SSGC Exhibit 6, which depicts the boundaries of the City of Leesburg, the City of Wildwood, and the City of Coleman, demonstrates that most, if not all, of the area encompassed by the Bigham developments is within the Wildwood city limits. In 2015, the interstate Sabal Trail transmission pipeline was being extended south through Sumter County. The line was originally expected to run in close proximity to Interstate 75. Even at that location, Leesburg decided that it would construct a gate station connecting to the Sabal Trail pipeline to provide backfill capabilities for its existing facilities in Lake County, and for its Coleman prison customer. In 2016, the Sabal Trail pipeline was redirected to come much closer to the municipal limits of Leesburg. That decision made the Leesburg determination to locate a gate station connecting to the Sabal Trail pipeline much easier. In addition, construction of the gate station while the Sabal Trail pipeline was under construction made construction simpler and less expensive. By adding the connecting lines to the Sabal Trail pipeline while it was under construction, a “hot tap” was not required. In May 2016, PGS began extending its gas distribution facilities to serve industrial facilities south of Coleman. It started from the terminus of its existing main at the intersection of SR 44 and CR 468 -- roughly a mile and a half west of the Lake County/Sumter County line and the Leesburg city limit -- along CR 468 to the intersection with U.S. Highway 301 (“US 301”), and extending along US 301 to the town of Coleman by January 2017. The distribution line was then extended south along US 301 to Sumterville.2/ In addition, Sumter County built a line off of the PGS line to a proposed industrial customer/industrial park to the south and west of Coleman, which was assigned to PGS. It is common practice for investor-owned utilities to extend service to an anchor customer, and to size the infrastructure to allow for the addition of customers along the route. By so doing, there is an expectation that a line will be fully utilized, resulting in lower customer cost, and a return on the investment. Nonetheless, PGS has not performed an analysis of the CR 468/US 301 line to determine whether PGS would be able to depreciate those lines and recover the costs. The CR 468/US 301 PGS distribution line is an eight- inch line, which is higher capacity in both size and pressure. The entire line is ceramic-coated steel with cathodic protection, which is the most up-to-date material. PGS sized the CR 468/US 301 distribution line to handle additional capacity to serve growth along the corridor. Although PGS had no territorial or developer agreement relating to any area of The Villages when it installed its CR 468/US 301 distribution line, PGS expected growth in the area, whether it was to be from The Villages or from another developer. Although it did not have specific loads identified, the positioning of the distribution line anticipated residential and commercial development along its route. Nonetheless, none of the PGS lines were extended specifically for future Villages developments. PGS had no territorial agreement, and had no discussion with The Villages about serving any development along the mains. PGS constructed a gate station at the intersection of CR 468 and CR 501 connecting to the Sabal Palm pipeline to serve the anchor industrial facilities. The Sabal Trail gate station was not constructed in anticipation of service to The Villages. Gas Service to The Villages In 2017, The Villages decided to extend gas service to its Fenney development, located along CR 468. Prior to that decision, The Villages had not constructed homes with gas appliances at any residential location in The Villages. The Villages has extended gas to commercial facilities associated with its developments north of SR 44, which had generally been provided by PGS. The Villages’ development in Fruitland Park in Lake County included commercial facilities with gas constructed, installed, and served by Leesburg. Prior to the time in which the Fenney development was being planned, The Villages began to require joint trenching agreements with various utilities contracted to serve The Villages, including water, sewer, cable TV, irrigation, and electric lines. Pursuant to these trenching agreements, The Villages’ contractors excavate a trench to serve residential facilities prior to construction of the residences. The trenches are typically four-feet-wide by four-feet-deep. Each of the utilities install their lines in the trench at a designated depth and separation from the other utility lines in order to meet applicable safety requirements. Using a common trench allows for uniformity of installation and avoids installation mishaps that can occur when lines are installed after other lines are in the ground. The trenching agreements proved to be effective in resolving issues of competing and occasionally conflicting utility line development. The PGS CR 468 distribution line runs parallel to CR 468 along the northern boundary of the Fenney development. Therefore, PGS was selected to provide service when the decision was made to extend gas service into Fenney. PGS entered into a developer agreement with The Villages that was limited to work in Fenney. PGS was brought into the Fenney development project in August 2017, after four development units had been completed. Therefore, PGS had to bring gas service lines into residences in those units as a retrofitted element, and not as a participant to the trenching agreements under which other utilities were installed. There were occasions during installation when the PGS installation contractor, R.A.W. Construction, severed telephone and cable TV lines, broke water and sewer lines, and tore up landscaped and sodded areas. As a result, homes in the four completed Fenney development units were delayed resulting in missed closing dates. However, since PGS was not brought in until after the fact for the four completed developments, it is difficult to assign blame for circumstances that were apparently not uncommon before joint trench agreements were implemented, and which formed the rationale for the creation of joint trench agreements.3/ The Villages was not satisfied with the performance of PGS at its Fenney development. The problems described by The Villages related to construction and billing services. The Villages also complained that PGS did not have sufficient manpower to meet its exceedingly rigid and inflexible construction requirements. Mr. McDonough indicated that even in those areas in which PGS was a participant in joint trenching agreements, it was incapable of keeping up with the schedule. Much of that delay was attributed to its contractor at the time, R.A.W. Construction. After some time had passed, PGS changed contractors and went with Hamlet Construction (“Hamlet”), a contractor with which The Villages had a prior satisfactory relationship. After Hamlet was brought in, most of the construction-related issues were resolved. However, Mr. Lovo testified that billing issues with PGS were still unsatisfactory, resulting in delays in transfer of service from The Villages to the residential home buyer, and delays and mistakes in various billing functions, including rebates. In late 2017, as the Fenney development was approaching buildout, The Villages commenced construction of the Bigham developments. The three Bigham developments were adjacent to one another. The Bigham developments will collectively include 4,200 residential homes, along with commercial support facilities. By September 27, 2017, Leesburg officials were having discussions with Mr. Geoffroy, a representative of its gas purchasing cooperative, Florida Gas Utility (“FGU”), as to how it might go about obtaining rights to serve The Villages’ developments. Mr. Rogers inquired, via email, “[w]hat about encroachment into [PGS] territory north of 468, which is where they plan to build next? [PGS] has a line on 468 that is feeding the section currently under development.” Some 15 minutes later, Mr. Geoffroy described the “customer preference” plan that ultimately became a cornerstone of this case as follows: Yes, the areas that the Villages “plans” to build is currently “unserved territory”, so the PSC looks at a lot of factors, such as construction costs, proximity of existing infrastructure and other things; however, the rule goes on to state that customer preference is an over-riding factor; if all else is substantially equal. In this case, simply having the Villages say they will only put gas into the homes if Leesburg serves them, but not TECO/PGS, will do it. (emphasis added). On November 16, 2017, Leesburg was preparing for a meeting with The Villages to be held “tomorrow.” Among the topics raised by Mr. Rogers was “territorial agreement?” to which Mr. Geoffroy responded “[d]epends on which option [The Villages] choose. If they become the utility, then yes. If not, you will eventually need an agreement with [PGS].” During this period of time, PGS had no communication with either Leesburg or The Villages regarding the extension of gas service to Bigham. PGS became aware that Hamlet was installing gas lines along CR 501 and CR 468 in late December 2017. PGS had not authorized those installations. Bigham West adjoined Fenney, and PGS had lines in the Fenney development that could have established a point of connection to the Bigham developments without modification of the lines. In addition, each of the three Bigham developments front onto CR 468 and are contiguous to the CR 468 PGS distribution line. The distance from the PGS line directly into any of the Bigham developments was a matter of 10 to 100 feet. The cost to PGS to extend gas service into Bigham would have been minimal, with “a small amount of labor involved and a couple feet of pipe.” PGS met with Leesburg officials in January 2018 to determine what was being constructed and to avoid a territorial dispute. PGS was directed by Leesburg to contact The Villages for details. Thereafter, PGS met with representatives of The Villages. PGS was advised that The Villages was “unappreciative” of the business model by which The Villages built communities, and a public utility was able to serve the residential customers and collect the gas service revenues for 30 or 40 years. The Agreement The Villages was, after the completion of Fenney, unsure as to whether it would provide gas service to Bigham, or would continue its past practice of providing all electric homes. The Villages rebuffed Leesburg’s initial advances to extend gas service to The Villages’ new developments, including Bigham. Thereafter, The Villages undertook a series of discussions with Leesburg as to how gas service might be provided to additional Villages’ developments in a manner that would avoid what The Villages’ perceived to be the inequity of allowing a public utility to serve The Villages’ homes, with the public utility keeping the revenues from that service. Leesburg and The Villages continued negotiations to come to a means for extending gas service to The Villages’ developments, while allowing The Villages to collect revenues generated from monthly customer charges and monthly “per therm” charges. SSGC was formed as a natural gas construction company to engage in those discussions. SSCG was, by its own acknowledgement, “an affiliate of The Villages, and the de facto proxy for The Villages in this proceeding.” On January 3, 2018, Leesburg internally discussed how to manage the issue of contributions in aid of construction (“CIAC”). It appeared to Mr. Rogers that gas revenues would continue to be shared with The Villages after its infrastructure investment, with interest, was paid off, with Mr. Rogers questioning “is there a legal issue with them continuing to collect revenue after their capital investment is recovered? Admittedly that may not occur for 15 years.” A number of tasks to be undertaken by The Villages “justifying the continued revenue stream” were proposed, with Mr. Geoffroy stating that: While this may seem a large amount for very little infrastructure, I think it would probably be okay. Because [PGS] distribution is so close, and the Villages has used them previously, it would be relatively easy for the Villages to connect to [PGS] and disconnect from [Leesburg], at any point in the future. In order to get and retain the contract, this is what [Leesburg] has to agree to win the deal. Not sure anyone has rate jurisdiction on this anyway, other than [Leesburg]. Those discussions led to the development of the Agreement under which service to Bigham was ultimately provided. The Agreement was a formulaic approach to entice The Villages into allowing Leesburg to be the gas provider for the residents that were to come. The Agreement governs the construction, purchase, and sale of natural gas distribution facilities providing service to residential and commercial customers in The Villages’ developments. On February 12, 2018, the Leesburg City Commission adopted Resolution 10,156, which authorized the Mayor and City Clerk to execute the Agreement on the Leesburg’s behalf. The Agreement was thereupon entered into between Leesburg and SSGC, with an effective date of February 13, 2018. Then, on February 26, 2019, the Leesburg City Commission adopted Ordinance 18-07, which enacted the Villages Natural Gas Rate Structure and Method of Setting Rates established in the Agreement into the Leesburg Code of Ordinances. The Agreement has no specific term of years, but provides for a term “through the expiration or earlier termination of [Leesburg]’s franchise from the City of Wildwood.” Mr. Minner testified that “the length of the agreement is 30 years from when a final home is built, and then over that overlay is the 30-year franchise agreement from the City of Wildwood.” However, SSGC’s response to interrogatories indicates that the Agreement has a 30-year term. Though imprecise, the 30-year term is a fair measure of the term of the Agreement. For the Bigham developments, i.e., the Agreement’s original “service area,” facilities are those installed into Bigham from the regulator station at the end of Leesburg’s new CR 501 distribution line, and include distribution lines along Bigham’s roads and streets, all required service lines, pressure regulator stations, meters and regulators for each customer, and other appurtenances by which natural gas will be distributed to customers. The Agreement acknowledges that Leesburg and SSGC “anticipate that the service Area will expand as The Villages® community grows, and thus, as it may so expand, [Leesburg and SSGC] shall expand the Service Area from time to time by written Amendment to this Agreement.” SSGC is responsible for the design, engineering, and construction of the natural gas facilities within Bigham. SSGC is responsible for complying with all codes and regulations, for obtaining all permits and approvals, and arranging for labor, materials, and contracts necessary to construct the system. Leesburg is entitled to receive notice from SSGC prior to the construction of each portion of the natural gas system, and has “the right but not the obligation” to perform tests and inspections as the system is installed. The evidence indicates that Leesburg has assigned a city inspector who is on-site daily to monitor the installation of distribution and service lines. SSGC has, to date, been using Hamlet as its contractor, the same company used by PGS to complete work at Fenney. Upon completion of each section in the development, SSGC provides Leesburg with a final inspection report and a set of “as-built” drawings. SSGC then conveys ownership of the gas distribution system to Leesburg in the form of a Bill of Sale. Upon the conveyance of the system to Leesburg, Leesburg assumes responsibility for all operation, maintenance, repairs, and upkeep of the system. Leesburg is also responsible for all customer service, emergency and service calls, meter reading, billing, and collections. Upon conveyance, Leesburg operates and provides natural gas service to Bigham through the system and through Leesburg’s facilities “as an integrated part of [Leesburg’s] natural gas utility operations.” In order to “induce” SSGC to enter into the Agreement, and as the “purchase price” for the system constructed by SSGC, Leesburg will pay SSCG a percentage of the monthly customer charge and the “per therm” charge billed to Bigham customers. Leesburg will charge Bigham customers a “Villages Natural Gas Rate” (“Villages Rate”). The “per therm” charge and the monthly customer charge for each Bigham customer are to be equal to the corresponding rates charged by PGS. If PGS lowers its monthly customer charge after the effective date of the agreement, Leesburg is not obligated to lower its Villages Rate. Bigham customers, who are outside of Leesburg’s municipal boundaries and unable to vote in Leesburg municipal elections, will pay a rate for gas that exceeds that of customers inside of Leesburg’s municipal boundaries and those inside of Leesburg’s traditional service area. A preponderance of the evidence indicates that for the term of the agreement, The Villages will collect from 52 percent (per Mr. Minner at hearing) to 55 percent (per Mr. Minner in deposition) of the total gas revenues paid to Leesburg from Bigham customers. The specific breakdown of revenues is included in the Agreement itself, and its recitation here is not necessary. The mechanism by which The Villages, through SSGC, receives revenue from gas service provided by Leesburg, first to its “proxy” customer and then to its end-user customers, is unique and unprecedented. It has skewed both competitive and market forces. Nonetheless, PGS was not able to identify any statute or rule that imposed a regulatory standard applicable to municipal gas utilities that would prevent such an arrangement. The evidence establishes that, under the terms of the Agreement, Leesburg is the “natural gas utility” as that term is defined by statute and rule. The evidence establishes that SSGC is, nominally, a gas system construction contractor building gas facilities for Leesburg’s ownership and operation. The evidence does not establish that the Agreement creates a “hybrid” public utility. Extension of Service to the Bigham Developments Leesburg’s mains nearest to Bigham were at SR 44 at the Lake County/Sumter County line, a distance of approximately 3.5 miles from the nearest Bigham point of connection; and along CR 470, a distance of approximately 2.5 miles to the nearest Bigham point of connection. When the Agreement was entered, neither the Leesburg 501 line nor the Leesburg 468 line were in existence. At the time the Agreement was entered, Leesburg knew that PGS was the closest provider to the three Bigham developments. In order to serve Bigham, Leesburg constructed a distribution line from a point on CR 470 near the Coleman Prison northward along CR 501 for approximately 2.5 miles to the southern boundary between Bigham West and Bigham East. Leesburg constructed a second distribution line from the Lake County line on SR 44 eastward to its intersection with CR 468, and then southward along CR 468 to the Florida Turnpike, just short of the boundary with Bigham East, a total distance of approximately 3.5 miles. The Leesburg CR 468 line will allow Leesburg to connect with the Bigham distribution line and “loop” or “backfeed” its system to provide redundancy and greater reliability of service to Bigham and other projects in The Villages as they are developed. The new Leesburg CR 468 line runs parallel to the existing PGS CR 468 line along its entire CR 468 route, and crosses the PGS line in places. There are no Commission regulations that prohibit crossing lines, or having lines in close proximity. Nonetheless, having lines in close proximity increases the risk of, among other things, complicating emergency response issues where fire and police believe they are responding to one utility's emergency when it is the other’s emergency. Safety Although PGS was the subject of a Commission investigation and violation related to a series of 2013-2015 inspections, those violations have been resolved to the satisfaction of the Commission. Mr. Szelistowski testified that PGS has received no citations or violations from the Commission, either from a construction standpoint or an operation and maintenance standpoint, for the past three years. Mr. Moses testified that both PGS and Leesburg are able to safely provide natural gas service to customers in Sumter County. His testimony is credited. Given the differences in size, geographic range, nature, and density of areas served by the PGS and Leesburg systems, the prior violations are not so concerning as to constitute a material difference in the outcome of this case. All of the distribution and service lines proposed by Leesburg and PGS to serve and for use in the disputed territory are modern, safe, and state-of-the-art. Reliability As stated by Leesburg in its PRO, “[t]he reliability of a natural gas distribution system to serve a designated area depends on the nature, location and capacity of the utility's existing infrastructure, the ability of the utility to secure the necessary quantities of natural gas, and the ability of the natural gas utility to supply gas in a safe manner.” As set forth herein, the location of PGS’s existing infrastructure, vis-a-vis the disputed territory, weighs strongly in its favor. As to the other reliability factors identified by Leesburg, both parties are equally capable of providing reliable service to the disputed territory. Both PGS and Leesburg demonstrated that they have the managerial and operational experience to provide service in the disputed area. There was no evidence to suggest that end-user customers of either Leesburg or PGS, including PGS’s Fenney customers, are dissatisfied with their service. Regulatory Standards for Territorial Disputes Rule 25-7.0472 establishes the criteria for the resolution of territorial disputes regarding gas utilities. Rule 25-7.0472(2)(a) Rule 25-7.0472(2)(a) includes the following issues for consideration in resolving a territorial dispute regarding gas utilities: The capability of each utility to provide reliable natural gas service within the disputed area with its existing facilities and gas supply contracts. Leesburg currently obtains its natural gas supply from the Florida Gas Transmission (“FGT”) distribution system, and purchases natural gas through FGU, a not-for-profit joint action agency, or "co-op" for purchasing natural gas. FGU's membership consists of city or governmental utility systems in Florida that distribute natural gas to end-user customers, or that use natural gas to generate electricity. FGU purchases and provides gas and manages interstate pipeline capacity for its members. FGU's members contractually reserve space in interstate transmission lines. FGU aggregates its members’ contracts into a single consolidated contract between FGU and the interstate pipelines and collectively manages its members’ needs through that contract. FGU has flexibility to transfer pipeline capacity from one member to benefit another member. Leesburg currently takes its natural gas through a "lateral" pipeline from the FGT transmission line. Gas travels through one of two gate stations, one in Haines Creek, and the other near the Leesburg municipal airport, both of which are located in Leesburg’s northeast quadrant. At the gate stations, transmission pressure is reduced to lower distribution pressure, and the gas is metered as it is introduced into Leesburg’s distribution system. The FGT transmission capacity is fully subscribed by FGU. Leesburg has not fully subscribed its lateral pipeline and has sole access to its lateral line capacity. Prior to the entry of the Agreement, and Leesburg/SSGC’s extension of distribution lines along CR 501 and CR 468, Leesburg’s distribution lines extended into Sumter County only along CR 470 to the Coleman Federal Prison. One other Leesburg line extended to the county line along SR 44, and then north to serve a residential area in Lake County. Leesburg argues that it has already extended lines, and is providing service to thousands of homes in Bigham, and that those facilities should be considered in determining whether it can “provide reliable natural gas service within the disputed area with its existing facilities.” PGS did not know of Leesburg’s intent to serve Bigham until late December 2017, when it observed PGS’s Fenney contractor, Hamlet, installing lines along CR 468, lines that it had not approved. PGS met with Leesburg officials in January 2018 to determine what was being constructed and to avoid a territorial dispute. PGS was directed by Leesburg to contact The Villages for details. PGS filed its territorial dispute on February 23, 2018, 10 days from the entry of the Agreement, and three days prior to the adoption of Ordinance 18-07. Construction of the infrastructure to serve Bigham occurred after the filing of the territorial dispute. Given the speed with which The Villages builds, hundreds of homes have been built, and gas facilities to serve have been constructed, since the filing of the territorial dispute. To allow Leesburg to take credit for its facilities in the disputed territory, thus prevailing as a fait accompli, would be contrary to the process and standards for determining a territorial dispute. The territory must be gauged by the conditions in the disputed territory prior to the disputed extension of facilities to serve the area. Leesburg’s existing facilities, i.e., those existing prior to extension to the disputed territory, were sufficient to serve the needs of Leesburg’s existing service area. The existing facilities were not sufficient to serve the disputed territory without substantial extension. 2. The extent to which additional facilities are needed. Both PGS and Leesburg have sufficient interconnections with transmission pipelines. Prior to commencement of construction at Bigham, the area consisted of undeveloped rural land. As discussed herein, the “starting point” for determining the necessity of facilities is the disputed territory property before the installation of site-specific interior distribution and service lines. To find otherwise would reward a “race to serve.” PGS demonstrated that it is capable of serving the disputed territory with no additional facilities needed. Its distribution mains are located directly adjacent to the disputed territory from the Fenney development from the west, and are contiguous to each of the Bigham developments from CR 468. The PGS CR 468 line was not constructed in specific anticipation of serving Bigham, and its cost is not fairly included in PGS’s cost to provide natural gas service to the disputed area presently and in the future. PGS’s existing distribution mains are capable of providing service to Bigham literally within feet of a point of connection. PGS’s cost to reach the disputed territory from its existing facilities in Fenney was estimated at $500 to $1,000. The cost of connecting the interior Bigham service lines to PGS’s CR 468 line is, at most, $10,000. PGS’s total cost of extending gas distribution lines to serve Bigham is, at most, $11,000. The evidence demonstrated that Leesburg required substantial additional facilities to serve the disputed territory. In order to meet the needs for reliable service to Bigham established in the Agreement, Leesburg constructed a new high-pressure distribution line from the existing CR 470 line north along CR 501 to Bigham for a distance of 2.5 miles at a cost of $651,475. The CR 501 line was constructed in specific anticipation of serving Bigham and is fairly included in Leesburg’s cost to provide natural gas service to the disputed area presently and in the future. In order to meet the needs for reliable service to Bigham established in the Agreement, Leesburg constructed a new high-pressure distribution line along SR 44 and CR 468 to Bigham for a distance of 3.5 miles at a cost of $560,732. The CR 468 segment of Leesburg’s line is adjacent and parallel to PGS’s existing CR 468 pipeline. Leesburg plans to connect the CR 468 line with the CR 501 line by way of a regulator station to create a system loop. Although Leesburg’s CR 468 pipeline is, ostensibly, not the primary distribution line for Bigham, it is directly related to the CR 501 line, and provides desired redundancy and reliability for Bigham, as well as infrastructure for the further expansion of Leesburg’s gas system to The Villages. Thus, the cost of extending Leesburg’s CR 468 line is fairly included in Leesburg’s cost as an “additional facility” to provide “reliable natural gas service,” to the disputed area presently and in the future. Leesburg’s total cost of extending gas distribution lines designed as primary distribution or redundant capability to serve Bigham is a minimum of $1,212,207. In addition to the foregoing, Leesburg, in its response to interrogatories, indicated that it “anticipates spending an amount not to exceed approximately $2.2 million dollars for gas lines located on county roads 501 and 468.” Furthermore, Leesburg stated that “[a]n oral agreement exists [between Leesburg and SSGC] that the amount to be paid by Leesburg for the construction of natural gas infrastructure on county roads 468 and 501 will not exceed $2.2 million dollars. This agreement was made . . . on February 12, 2018.” That is the date on which Leesburg adopted Resolution 10,156, which authorized the Mayor and City Clerk to execute the Agreement on Leesburg’s behalf. The context of those statements suggests that the total cost of constructing the gas infrastucture to serve Bigham could be as much as $2.2 million. PGS argues that Leesburg’s cost of connecting to the Sabal Trail transmission line should be included in the cost of serving the disputed territory. Leesburg began planning and discussions to connect to Sabal Trail as early as 2015, when the construction of Sabal Trail through the area became known. Leesburg entered into a contract for the Sabal Trail connection in February 2016. The Sabal Trail connection was intended to provide Leesburg with additional redundant capacity for its system independent of service to The Villages. The cost of constructing the Sabal Trail gate station is not fairly included in Leesburg’s cost to provide natural gas service to the disputed area presently and in the future. Rule 25-7.0472(2)(b) Rule 25-7.0472(2)(b) includes the following issues for consideration in resolving a territorial dispute regarding gas utilities: The nature of the disputed area and the type of utilities seeking to serve it. The area in dispute was, prior to the commencement of construction, essentially rural, with rapidly encroaching residential/commercial development. Although the area was generally rural at the time PGS installed its CR 468/US 301 distribution line, there was a well-founded expectation that development was imminent, if not by The Villages, then by another residential developer. The disputed territory is being developed as a master-planned residential community with associated commercial development. The Bigham developments are currently proximate to the Fenney development. Other non-rural land uses in the area include the Coleman Federal Prison and the American Cement plant. As indicated, Leesburg is a municipal gas utility, and PGS is a public gas utility. The utilities seeking to serve the disputed territory are both capable, established providers with experience serving mixed residential and commercial areas. There is nothing with regard to this factor that would tip the balance in either direction. 2. The degree of urbanization of the area and its proximity to other urban areas. As it currently stands, the disputed territory is bounded to its south and east by generally undeveloped rural property, to its south by rural property along with the Coleman Prison and American Cement plant, to its west by the Fenney development and additional undeveloped rural property, and to its north by low-density residential development. The disputed territory is characterized by residential areas of varying density, interspersed with commercial support areas. The nearest of the “town centers,” which are a prominent feature of The Villages development, is Brownwood Paddock Square, which is located north of SR 44, and a few miles north of Fenney and Bigham. The town center is not in the disputed territory. The terms “urban” and “rural” are not defined in Florida Administrative Code chapter 25-7, or in chapter 366. Thus, application of the common use of the term is appropriate. “Urban” is defined as “of, relating to, characteristic of, or constituting a city.” Merriam-Webster, https://www.merriam- webster.com/dictionary/urban. “Rural” is defined as “of or relating to the country, country people or life, or agriculture.” Merriam-Webster, https://www.merriam- webster.com/dictionary/rural. The disputed territory was rural prior to the development of Bigham. The area is becoming more loosely urbanized as The Villages has moved into the area and is expected to experience further urban growth to the south and east. Fenney and Bigham are, aside from their proximity to one another, not currently proximate to other urban areas. There is nothing with regard to this factor that would tip the balance in either direction. 3. The present and reasonably foreseeable future requirements of the area for other utility services. Since the disputed territory is a completely planned development, there are requirements for basic utilities. Leesburg provides other utility services to the greater Leesburg MSA and the Villages Fruitland Park development, including electric, water, and sewer service, and has, or is planning to provide such services to other developments for The Villages in the area. Leesburg’s ability to provide other utility services to The Villages in addition to gas service is a factor in Leesburg’s favor. Rule 25-7.0472(2)(c) Rule 25-7.0472(2)(c) establishes that the cost of each utility to provide natural gas service to the disputed area presently and in the future is an issue for consideration in resolving a territorial dispute regarding gas utilities. Various costs are broken out in subparagraphs 1. through 9. of the rule, and will be addressed individually. However, it is clear, as set forth in the facts related to rule 25-7.0472(2)(a) above, that the cost of extending service into Bigham was substantially greater for Leesburg than for PGS. The individually identified costs include the following: Cost of obtaining rights-of-way and permits. There was no evidence to suggest that the cost of obtaining rights-of-way and permits for the construction of the gas infrastructure described herein varied between Leesburg and PGS. There is nothing with regard to this factor that would tip the balance in either direction. 2. Cost of capital. The parties stipulated that the issue of cost of capital is not applicable to this dispute. 3. Amortization and depreciation. The parties stipulated that the issues of amortization and depreciation are not applicable to this dispute. 4. through 6. Cost-per-home. The cost-per-home for extending service to homes in Bigham includes the costs identified in rule 25-7.0472(2)(c)4. (labor; rate per hour and estimated time to perform each task), rule 25-7.0472(2)(c)5. (mains and pipe; the cost per foot and the number of feet required to complete the job), and rule 25- 7.0472(2)(c)6. (cost of meters, gauges, house regulators, valves, cocks, fittings, etc., needed to complete the job). The cost-per-home for Leesburg and SSGC is $1,800 (see ruling on Motion to Strike). In addition, Leesburg will be installing automated meters at a cost of $72.80 per home. The preponderance of the evidence indicates that the PGS cost-per-home is $1,579, which was the cost-per-home of extending service in the comparable Fenney development. The cost-per-home is a factor -- though slight -- in PGS’s favor. 7. Cost of field compressor station structures and measuring and regulating station structures. None of the parties specifically identified or discussed the cost of field compressor station structures and measuring and regulating station structures in the Joint Pre- hearing Stipulation or their PROs. Thus, there is little to suggest that the parties perceived rule 25-7.0472(2)(c)7. to be a significant factor in the territorial dispute. As a result, there is nothing with regard to this factor that would tip the balance in either direction. 8. Cost of gas contracts for system supply. None of the parties specifically identified or discussed the cost of the respective gas contracts for system supply in the Joint Pre-hearing Stipulation or their PROs. Thus, there is little to suggest that the parties perceived rule 25-7.0472(2)(c)8. to be a significant factor in the territorial dispute. As a result, there is nothing with regard to this factor that would tip the balance in either direction. 9. Other costs that may be relevant to the circumstances of a particular case. There was considerable evidence and testimony as to the revenues that would flow to SSGC under the 30-year term of the Agreement. SSGC's revenues under the Agreement are not relevant as they are not identified as such in rule 25-7.0472, and are not directly related to the rates, which will likely not exceed PGS’s regulated rate. Rule 25-7.0472(2)(d) Rule 25-7.0472(2)(d) includes that the Commission may consider “other costs that may be relevant to the circumstances of a particular case.” This factor is facially identical to that in rule 25-7.0472(2)(c)9., but is, nonetheless, placed in its own rule section and must therefore include costs distinct from those to provide natural gas service to the disputed area presently and in the future. Cost of service to end-user customers. Due to the nature of the Agreement, Leesburg will charge a “Villages Rate” that will be equal to the fully regulated PGS rate.4/ Thus, as a general rule, the cost of service to end-user customers will be the same for PGS and Leesburg. There is nothing with regard to this factor that would tip the balance in either direction. 2. Uneconomic duplication of facilities. Neither section 366.04(3), nor rule 25-7.0472, pertaining to natural gas territorial disputes, expressly require consideration of “uneconomic duplication of facilities” as a factor in resolving territorial disputes. The Commission does consider whether a natural gas territorial agreement “will eliminate existing or potential uneconomic duplication of facilities” as provided in rule 25-7.0471. A review of Commission Orders indicates that many natural gas territorial dispute cases involve a discussion of uneconomic duplication of facilities because disputes are frequently resolved by negotiation and entry of a territorial agreement. In approving the resultant agreement, the Commission routinely considers that the disposition of the dispute by agreement avoids uneconomic duplication of facilities. See In re: Petition to Resolve Territorial Dispute with Clearwater Gas System, a Division of the City of Clearwater, by Peoples Gas System, Inc., 1995 Fla. PUC LEXIS 742, PSC Docket No. 94-0660-GU; Order No. PSC-95-0620- AS-GU (Fla. PSC May 22, 1995)(“[W]e believe that the territorial agreement is in the public interest, and its adoption will further our longstanding policy of avoiding unnecessary and uneconomic duplication of facilities. We approve the agreement and dismiss the territorial dispute.); In re: Petition by Tampa Electric Company d/b/a Peoples Gas System and Florida Division of Chesapeake Utilities Corporation for Approval of Territorial Boundary Agreement in Hillsborough, Polk, and Osceola Counties, 1999 Fla. PUC LEXIS 2051, Docket No. 990921-GU; Order No. PSC-99-2228-PAA-GU181 (Fla. PSC Nov. 10, 1999)(“Over the years, CUC and PGS have engaged in territorial disputes. As each utility expands its system, the distribution facilities become closer and closer, leading to disputes over which is entitled to the unserved areas. The purpose of this Agreement is to set forth new territorial boundaries to reduce or avoid the potential for future disputes between CUC and PGS, and to prevent the potential duplication of facilities.”); In re: Joint Petition for Approval of Territorial Agreement in DeSoto County by Florida Division of Chesapeake Utilities Corporation and Sebring Gas System, Inc., 2017 Fla. PUC LEXIS 163, Docket No. 170036-GU; Order No. PSC-17-0205-PAA-GU (Fla. PSC May 23, 2017)(“The joint petitioners stated that without the proposed agreement, the joint petitioners’ extension plans would likely result in the uneconomic duplication of facilities and, potentially, a territorial dispute . . . . [W]e find that the proposed agreement is in the public interest, that it eliminates any potential uneconomic duplication of facilities and will not cause a decrease in the reliability of gas service.”). There are Commission Orders that suggest the issue of uneconomic duplication of facilities is an appropriate field of inquiry in a territorial dispute even when it does not result in a territorial agreement. See In re: Petition to Resolve Territorial Dispute with South Florida Natural Gas Company and Atlantic Gas Corporation by West Florida Natural Gas Company, 1994 Fla. PUC LEXIS 1332, Docket No. 940329-GU; Order No. PSC-94-1310-S-GU (Fla. PSC Oct. 24, 1994)(“On March 31, 1994, West Florida filed a Petition to Resolve a Territorial Dispute with South Florida and Atlantic Gas On August 26, 1994, West Florida, South Florida, and Atlantic Gas filed a Joint Petition for Approval of Stipulation, which proposed to resolve the territorial dispute by West Florida's purchase of the Atlantic Gas facilities . . . . We believe that approval of the joint stipulation is in the public interest because its adoption will avoid unnecessary and uneconomic duplication of facilities.”). The evidence in this case firmly establishes that Leesburg’s extension of facilities to the Bigham developments, both through the CR 501 line and the CR 468 line, constituted an uneconomic duplication of PGS’s existing gas facilities. As set forth in the Findings of Fact, PGS’s existing gas line along CR 468 is capable of providing safe and reliable gas service to the Bigham developments at a cost that is negligible. To the contrary, Leesburg extended a total of roughly six miles of high-pressure distribution mains to serve the Bigham developments at a cost of at least $1,212,207, with persuasive evidence to suggest that the cost will total closer to $2,200,000. This difference in cost, even at its lower end, is far from de minimis, and constitutes a significant and entirely duplicative cost for service. Leesburg argues that if uneconomic duplication of facilities is a relevant factor, “the evidence of record demonstrates that the City will suffer significant financial impact if it is not permitted to continue to serve the Bigham Developments.” The fact that Leesburg, with advance knowledge and planning, was able to successfully race to serve Bigham, incurring its “financial impact” after the territorial dispute was filed, does not demonstrate either that PGS meets the standards to prevail in this proceeding, or that PGS should be prevented from serving development directly adjacent to its existing facilities in the disputed territory. Rule 25-7.0472(2)(e) Rule 25-7.0472(2)(e) establishes that customer preference is the “tie-breaker” if all other factors are substantially equal. The Villages is the “customer” for purposes of the selection of the provider of natural gas service to Bigham. There is no dispute that The Villages, as the proxy for the individual end-user customers, has expressed its preference to be served by Leesburg. The direct financial benefit to The Villages, and Leesburg’s willingness to enter into a revenue sharing plan -- a plan that, if proposed by PGS, would likely not be allowed by the Commission in its rate- setting capacity -- no doubt plays a role in that decision. Gas service to end-user customers living in in Bigham will be a revenue-generating venture for The Villages if served by Leesburg, and will not if served by PGS. Leesburg and SSGC have suggested that customer preference should occupy a more prominent role in the dispute since gas service, unlike electric, water, and sewer services, is an optional utility service. SSGC argued that since The Villages expressed that it would forego providing gas service to its developments if PGS is determined to be entitled to serve -- a position oddly presaged by Mr. Geoffroy in his September 27, 2017, email with Leesburg (see paragraph 35) -- and “in consideration of the business practices, size, track record of success, and economic import of The Villages,” the preference of The Villages for service from Leesburg should “be a significant factor in the resolution of this dispute.” Neither of those reasons can serve to elevate customer preference from its tie-breaker status as established by rule.
Conclusions For Petitioner: Andrew M. Brown, Esquire Ansley Watson, Esquire Macfarlane Ferguson & McMullen Suite 2000 201 North Franklin Street Tampa, Florida 33602 Frank C. Kruppenbacher, Esquire Frank Kruppenbacher, P.A. 9064 Great Heron Circle Orlando, Florida 32836 For Respondent South Sumter Gas Company: John L. Wharton, Esquire Dean Mead & Dunbar 215 South Monroe Street, Suite 815 Tallahassee, Florida 32301 Floyd Self, Esquire Berger Singerman, LLP Suite 301 313 North Monroe Street Tallahassee, Florida 32301 For Respondent City of Leesburg: Jon C. Moyle, Esquire Karen Ann Putnal, Esquire Moyle Law Firm, P.A. 118 North Gadsden Street Tallahassee, Florida 32301
The Issue The issue in this case is whether, under Section 57.111, Florida Statutes, Respondent is liable for attorneys' fees and costs incurred by Petitioner in an earlier proceeding. The purpose of the earlier proceeding was to determine the eligibility of Petitioner's site for state-administered cleanup of discharge from a petroleum storage system under the Early Detection Incentive program described in Section 376.3071(9), Florida Statutes.
Findings Of Fact Petitioner informed Respondent of a pollutant discharge at Petitioner's gasoline station by filing a Discharge Notification Form on March 9, 1987. The form states that the discovery was made on March 5, 1987, as a result of a manual test of one or more monitoring wells. The form is marked "unknown" in response to questions concerning the estimated gallons lost, the part of storage system leaking, the type of tank, the cause of leak, and the type of pollutant discharged, although next to the last response are the typewritten words: "appears to be motor oil." A cover letter from Petitioner dated March 5, 1987, accompanied the Discharge Notification Form. The letter restates that the source of pollution is unknown, but adds that "there is a possibility that [the pollution] is the result of a septic tank, drain field discharge." The letter discloses that Blackhawk Environmental Services, Inc. ("Blackhawk") and NEPCCO/IT are investigating "to determine the extent of the contamination as well as the source." The letter provides the name and telephone number of the Blackhawk employee for further information. A separate cover letter from the Blackhawk employee to Respondent states that the notification was being submitted for consideration for Site Rehabilitation Reimbursement Costs. The letter also states that the site has been the subject of groundwater contamination from an "unknown source." Following the notification, Orlando Laboratories, Inc. submitted to Blackhawk a written analysis of the groundwater at the site. The report, which is dated March 19, 1987, contains quantitative data without any interpretation and was submitted without interpretation to Respondent on March 20, 1987. Petitioner applied to participate in the Early Detection Incentive ("EDI") Program by filing an EDI Program Notification Application dated March 23, 1987, together with a cover letter of the same date. The application supplied no more information than did the notification form. In response to the question as to the type of product discharged, Petitioner circled the choice, "used oil," but added the word, "possibility." Although the application may not have been immediately filed, Respondent received it prior to July, 1987. As part of a site inspection, an employee of Respondent prepared an Early Detection Incentive Program Compliance Verification Checklist, which was dated April 28, 1987. The checklist notes that Blackhawk "is looking into problem [and] will forward results from lab when available." The checklist also states: Odor found in E[ast] & W[est] M[onitoring] W[ells]. No other contamination found on site. Site has old waste oil tank on site that could possibly be contaminating drainfield next to tank. Also old abandoned tank (since 1967) on site. Asked owner to investigate tank's conditions. If not needed, he will remove & adjust registration accordingly. Floordrain in shop area dumps into on-site septic tank which could also contribute. The repeated mention of motor oil is due to at least two factors. First, a Blackhawk employee had mentioned to Belvin Marr, who owns and operates Petitioner, that the contaminant "looked like" motor oil. Second, Mr. Marr knew that he had, for many years, discarded used motor oil down a floordrain leading into a septic tank with an onsite drainfield. By letter dated July 22, 1989, Respondent informed Petitioner that its site was ineligible for state-administered cleanup under for the EDI program described in Section 376.3071(9), Florida Statutes. The letter states that the decision was "based upon information given in this [Notification Application] and a compliance verification evaluation of your reported site." The July 22 letter explains that the site is ineligible because, according to the application and district inspection: the source of contamination at Marr's Exxon has been attributed to used oil. Petroleum, as defined by Section 376.301(9), Florida Statutes (F.S.), included [sic] only crude oil and other hydrocarbons in the form in which they are originally produced at the well. Petroleum product, as defined by Section 376.301(10), F.S., means fuel in its refined state which is similar in nature to fuels such as diesel fuel, kerosene, or gasoline. Used oil cannot be considered "petroleum" or "petroleum products" because it has become unsuitable for its original purpose due to the presence of impurities or loss of original properties. Therefore, your site, which is contaminated by unrefined used oil, is not eligible for participation in Early Detection Incentive (EDI) Program. The July 22 letter advises Petitioner that he could obtain administrative and judicial review of the decision by filing a petition within 21 days of the date of receipt of the letter. The letter thus provided Petitioner with a clear point of entry. By letter dated July 30, 1987, Petitioner requested a 30-day extension to allow for retesting. Additional testing took place in early August, 1987. However, there is no indication that the resulting data, which again omit textual interpretation, were submitted to Respondent until the filing of the more definite statement described in the following paragraph. The next communication between Petitioner and Respondent took place when Petitioner requested a formal hearing by filing a Petition for Hearing dated August 26, 1987. By Order for More Definite Statement entered September 14, 1987, Respondent ordered Petitioner to file a more definite statement. By Response to Order for More Definite Statement dated September 28, 1987, Petitioner filed a more definite statement. The additional test data were attached to the more definite statement, although they are not in the DOAH case file. The Response offers the following chronology with all dates being approximate dates. March 5, 1987: Respondent notified of groundwater contamination from unknown source. March 20, 1987: analysis of contamination conducted by Orlando Laboratories, Inc. and forwarded to Respondent. March 23, 1987: Petitioner applied for participation in Early Detection Incentive ("EDI") program, and the application is attached to the More Definite Statement. April 27, 1987: Compliance Verification checklist issued. July 22, 1987: Respondent denied Petitioner's application. July 30, 1987: Petitioner requested 30-day extension to conduct further testing, the results of which are attached to the More Definite Statement. August 26, 1987: Petitioner requested formal administrative hearing. Following receipt of the more definite statement, Respondent forwarded the pleadings to the Division of Administrative Hearings for assignment of a Hearing Officer to conduct a hearing. The pleadings were received on October 9, 1987, and the file was assigned DOAH Case No. 87-4448. In a Motion for Continuance filed on January 14, 1988, Respondent asserted that the case involves the issue whether "used oil," which was what had been discharged at Petitioner's facility, is a "petroleum product." The motion refers to a pending case, Puckett Oil v. Department of Environmental Regulation, and states that this case, which had been heard in September, 1987, involves the same question. By Motion for Continuance filed on May 13, 1988, Respondent requested a continuance on the same grounds as previously cited and represented that Petitioner had no objection. An internal memorandum of Respondent dated March 17, 1988, acknowledges that Petitioner requested a review of the available data based on an "inaccurate assessment by his contractor." Reviewing the data, some of which had been provided after July 22, 1987, the memorandum notes that the majority of the contamination is from gasoline, but the involvement of the drainfield as the source of contamination "is the reason eligibility was denied." After the issuance of the final order in Puckett Oil v. Department of Environmental Regulation, 10 FALR 5525 (September 1, 1988), Respondent, filing a Motion to Set Hearing Date, disclosed that "[Respondent's] review of the Final Order indicates that Petitioner's site remains ineligible for SUPER Act funding." However, on July 28, 1989, the parties filed a fully executed Joint Stipulation and Motion to Dismiss. An Order Closing File, which was entered the same date, returned the matter to Respondent for final disposition consistent with the stipulation. The Joint Stipulation and Motion to Dismiss states: On July, 22, 1987, [Respondent] denied eligibility for the [EDI] Program, Section 376.3071(9), Florida Statutes, to [Petitioner's) site . . .. The basis for the denial was that the site was contaminated with used oil. Subsequent to [Respondent's] denial, Petitioner conducted a series of ground water tests to more accurately determine the nature and extent of contamination at the site. The results of that testing indicate that the site was contaminated with significant amounts of gasoline constituents and minor amounts of used oil constituents emanating possibly from a septic tank drainfield and a used oil storage facility. The gasoline constituents exist at levels many times that of the other constituents. Based upon the overwhelming contribution to the overall contamination presented by the gasoline constituents, [Respondent] agrees that the presence of minor amounts of contaminants from something other than a tank should not preclude [Petitioner's] site from being eligible for the EDI Program. [Respondent reserves the right not to pay for the cost of cleanup of contamination not related to discharge from a tank.] WHEREFORE Petitioner . . . and Respondent request that the hearing officer adopt this stipulation . . . and retain jurisdiction for an award of attorney's fees and costs (Fla. Stat. Sect. 57.111 (1986 Supp.) and Fla. Admin. Code Rule 22I-6.035). . .. The parties stipulated that Petitioner was a small business party. The parties also stipulated to reasonable attorneys' fees of $6625 and costs of $4690. Following the final hearing, Petitioner filed supplemental affidavits showing, in connection with the prosecution of the subject case and not the earlier proceeding, additional attorneys' fees of $1875 and costs of $490.85.
Findings Of Fact On November 5, 1987, a customer at Cowarts 66 service station complained of suspected water in the premium unleaded gasoline the customer had purchased at Cowarts 66 service station. Pursuant to the complaint, William Ford, an inspector for the Department, examined the premium unleaded gasoline storage facility at Cowarts 66 service station. The inspector obtained a sample of gasoline from the premium unleaded gasoline tank. The sample was examined by a Department of Agriculture chemist. There was no water found in the sample. However, the sample showed an end point of 455 degrees Fahrenheit which exceeded the maximum end point of 437 degrees Fahrenheit allowed by the Department under its rules governing petroleum products. Rule 5F-2.001(c)(4), F.A.C. The high end point was caused by the gasoline stored in the tank being mixed with or contaminated by another petroleum product with a high end point such as diesel fuel, thereby raising the end point of the premium unleaded. The contamination was caused by Clay Oil when their delivery driver accidentally mixed two fuels together and delivered the contaminated fuel to Cowarts 66. On November 6, 1987, the inspector issued a stop sale notice. The Department then has the right to confiscate the contaminated gasoline. However, the Department may elect to allow the station to post a bond in lieu of confiscation. In this case, the Department allowed Cowarts 66 to post a $1,000.00 bond in return for replacing the contaminated gasoline with gasoline meeting the Department's standards. The bond was posted the same day as the stop sale notice. The gasoline was likewise replaced either the same day or the morning after by Clay Oil. Cowarts 66 was later reimbursed by Clay Oil for the $1,000.00 cash bond. William Ford testified that he had been an inspector for Petitioner in the Jacksonville area for 16 years and had been familiar with Clay Oil Corporation and its operation for the past 10 or 15 years. He knew the corporation to be a reputable company. Prior to the instant case, he had never had any dealings with Clay Oil Corporation regarding dispensing of contaminated fuel. He had never had an occasion to require Clay Oil Corporation to post a bond. Ford, also, testified that the violation was clearly inadvertent and not representative of the normal business practices of Clay Oil Corporation. Furthermore, Ford testified that Clay Oil Corporation had been totally cooperative with the Department and had made immediate efforts to correct the violation regarding the contaminated fuel. Clay Oil Corporation's representative, Peter T. Eyrick, testified that upon being advised that contaminated fuel had been delivered to Cowarts' service station, he immediately instigated measures to replace the contaminated fuel with fuel that met Department standards. Furthermore, he testified that he had no knowledge that contaminated fuel had been delivered or that illegal sales had occurred until being informed by Cowarts' owner and the Department's inspector. The evidence clearly establishes that this violation was inadvertant and isolated. The violation is not representative of the normal business practice of Respondent. The evidence, also, clearly demonstrated that Respondent had no intent to sell adulterated fuel.
Recommendation Based upon the foregoing findings of fact and Conclusions of Law, it is RECOMMENDED that the Department refund to Clay Oil Corporation $750.00 of the $1,000.00 bond. DONE and ORDERED this 11th day of May, 1988, in Tallahassee, Florida. DIANE CLEAVINGER Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 11th day of May, 1988. APPENDIX CASE NO. 88-0181 Petitioner, Clay Oil Corporation, did not number its paragraphs in its recommended order. I, therefore, have numbered the paragraphs in its recommended order sequentially and utilize those numbers in this appendix. Petitioner's proposed findings of fact contained in paragraphs 1, 2, 3, 4 and 5, have been adopted, in substance, in so far as material. Respondent's proposed findings of fact contained in paragraphs 1, 2 and 3, have been adopted, in substance, in so far as material. Respondent's proposed findings of fact contained in paragraph 4 has been adopted, in substance, in so far as material, except for the finding regarding the number of gallons sold. The number of gallons sold was not shown by the evidence. Respondent's proposed findings of fact contained in paragraph 5 was not shown by the evidence. COPIES FURNISHED: Peter T. Eyrick Clay Oil Corporation Post Office Box 8 Doctors Inlet, Florida 32030 Harry Lewis Michael, Esquire Florida Department of Agriculture and Consumer Services Mayo Building Tallahassee, Florida 32399-0800 Paul S. Boone, Esquire 1221 King Street Jacksonville, Florida 32204 Honorable Doyle Connor Commissioner of Agriculture The Capitol Tallahassee, Florida 32399-0810 Ben Pridgeon, Chief Bureau of Licensing & Bond Department of Agriculture Lab Complex Tallahassee, Florida 32399-1650
The Issue The issues in these cases include the following: Did Petitioner file completed applications to entitle it to an oil and gas drilling permit? Is the Department's policy of requiring information in support of an offshore oil and gas well drilling permit not specifically set out in existing rules constitute an unadopted rule? If the Department applied an unadopted rule to Petitioner in these cases, does the unadopted rule meet the requirements of Section 120.57(1)(e), Florida Statutes? Is Petitioner entitled to the oil and gas drilling permits it sought by default?
Findings Of Fact The Parties. Petitioner, Coastal Petroleum Company (hereinafter referred to as "Coastal"), is a Florida corporation. Phillip Ware is the current president of Coastal. Respondent, the Florida Department of Environmental Protection (hereinafter referred to as the "Department"), is an agency of the State of Florida. The Department is charged with the responsibility of implementing Florida laws and rules regulating the issuance of oil and gas drilling permits. Intervenors are the Florida Wildlife Federation, Inc., Sierra Club, Florida Chapter, and the Florida Audubon Society, Inc. (hereinafter referred to as the "Environmental Intervenors"), and the Department of Legal Affairs (hereinafter referred to as "Legal Affairs"). The Environmental Intervenors and Legal Affairs filed verified petitions to intervene in this proceeding pursuant to Section 403.412(5), Florida Statutes. Coastal's Offshore Drilling Rights. On or about December 27, 1944, Coastal's predecessor entered into two leases, Drilling Lease Nos. 224-A and 224-B (hereinafter referred to as the "Original Leases"), with the predecessor to the Florida Board of Trustees of the Internal Improvement Fund. The Original Leases gave Coastal the exclusive right to explore for and produce oil and gas on submerged lands of the State of Florida throughout an area extending for a distance of 10.36 statute miles off most of the west coast of Florida. The area extends from approximately Apalachicola, Florida, in the north, to Naples, Florida, in the south. On or about February 27, 1947, the Original Leases were modified to redefine the area covered by the Leases due to claims of the federal government of parts of the area originally covered by the Original Leases (hereinafter referred to as the "Modified Leases"). In 1990 the Legislature enacted Chapter 90-72, Laws of Florida (1990), expressing the current policy of the State concerning offshore drilling. Pursuant to Chapter 90-72 the Legislature prohibited all offshore leasing and drilling. Recognizing Coastal's rights pursuant to the Modified Leases, an exception for drilling in areas governed by the Modified Leases was included in Chapter 90-72. Coastal is currently the only person entitled to explore for, and produce oil and gas on State submerged lands. Coastal's working interests under the Modified Leases were, as a result of litigation between the State and Coastal, subsequently reduced to the width of the area covered by the Modified Leases to between 7 miles and 10.36 miles from the coast. The litigation began during the late 1960's and ended with a settlement in 1976. Following the execution of the Original Leases and continuing through 1968, Coastal was involved with obtaining permits for, and drilling, approximately 9 wells in the area covered by the Original and/or Modified Leases. No permits were obtained by Coastal to drill in the area covered by the Modified Leases after 1968 due to the ongoing litigation between Coastal and the State. After the settlement of the dispute in 1976, Coastal was involved in litigation with Mobil Oil until the 1980's. Due to that litigation, Coastal did not pursue any other drilling operations under the Modified Leases until the 1980's. Because of the significant changes in the state of offshore drilling technology since Coastal had last applied for a permit to drill offshore in Florida, it took Coastal until the early 1990's to file a new application to drill offshore. Permit 1281. In March 1992 Coastal filed five separate applications with the Department seeking permits to drill exploratory oil and gas wells at five separate locations in the Gulf of Mexico within the area of the Modified Leases. Two applications were for proposed sites offshore from northwest Florida and three were for proposed sites offshore from southwest Florida. The applications were designated permit application numbers 1277 through 1281 by the Department. The applications filed by Coastal included a completed one-page Department form (Form 3), a location plat for the proposed drilling sites, and a filing fee. Coastal subsequently withdrew four of the applications. Only permit application 1281 remained. Pursuant to permit application 1281, Coastal sought approval to drill offshore from Franklin County, Florida, near St. George Island. In August 1996 the Department, after protracted negotiations with Coastal, issued notice of its intent to issue Permit 1281. The protracted negotiations involved, among other things, a request of the Department for additional information concerning the proposed location and drilling plans of Coastal. The additional information requested by the Department was essentially the same as the information requested by the Department in these cases. While Coastal provided the information concerning permit application 1281, it did so under protest. The Department's proposed decision to issue Permit 1281 was challenged. Following an administrative hearing, a Recommended Order was entered recommending that the permit be issued. The Department rejected the recommendation by Final Order issued May 22, 1998. That Final Order has been appealed by Coastal. Coastal's Applications for Permits 1296 through 1307. On or about February 25, 1997, Coastal simultaneously filed twelve separate applications (hereinafter referred to as the "Twelve Applications") with the Department seeking permits to drill exploratory oil and gas wells at twelve separate locations in the Gulf of Mexico within the area of the Modified Leases. Coastal Exhibits 49 through 60. The Twelve Applications were designated permit application numbers 1296 through 1307 by the Department. All of the proposed drilling sites are located between 8 and 9 miles offshore in water depths ranging between 50 to 75 feet. The general location of the twelve proposed drilling sites is as follows: Permit applications 1296 and 1297: offshore from St. George Island and Franklin County; Permit application 1298: offshore from the St. Marks River, Wakulla County; Permit application 1299: offshore from the mouth of the Steinhatchee River, Taylor County; Permit applications 1300 and 1301: offshore from Anclote Island, Pasco County; Permit application 1302: offshore from Longboat Key, Sarasota County; Permit applications 1303, 1304, and 1305: offshore from Gasparilla Island, Charlotte County; Permit application 1306: offshore from Sanibel Island, Lee County; and Permit application 1307: offshore from Naples, Collier County. The locations of the proposed exploratory wells are depicted on Coastal Exhibit 27, which is incorporated into this Recommended Order by reference. The Twelve Applications filed by Coastal consisted of the following: A completed Application For Permit to Drill, Form 3, for each well; A check payable to the Petroleum Exploration Bond Trust Fund as performance security for the twelve proposed wells; A navigation chart published by the U.S. Department of Commerce, National Oceanic and Atmospheric Administration, with the location (latitude and longitude) of each proposed drilling site and the area of Coastal's lease designated on the chart. The scale of the chart provided by Coastal is 1:20,000. A surveyor's report of the coordinates of each proposed drilling site was also included; and A single check in the amount of $24,000.00 in payment of the $2,000.00 application fee for each permit application. Form 3 requires that an applicant provide information concerning the name, phone number, and address of the applicant, the well name and its location, ground elevation, acres assigned to the well, the "field/area" of the well, the county and specific location of the well, proposed depth of the well, and the applicant's mineral interests in the drilling unit. Coastal provided all of this information. Form 3 also requires that the applicant answer a series of questions concerning whether the proposed location of the well will be located within: a municipality; tidal waters within 3 miles of a municipality; an improved beach; submerged land located in any bay or estuary; one mile seaward of the Florida coastline or the boundary of any state, or a local or federal park, or aquatic or wildlife preserve; on the surface of a freshwater body; within one mile inland from the shoreline of the Gulf of Mexico, the Atlantic Ocean or any bay or estuary; or within one mile of any freshwater body. Coastal answered all of the foregoing questions "no" on the Twelve Applications. Coastal did not provide a copy of its Organization Report (Department "Form 1") because it had already provided one to the Department. As provided in the Department's rules, Coastal informed the Department that its Organization Report was on file with the Department. Coastal did not initially provide casing and cementing plans or a contingency plan for hydrogen sulfide with the Twelve Applications. Ultimately, casing and cementing plans were provided by Coastal. Finally, Coastal requested that the Department conduct a preliminary site inspection, pursuant to the requirement of Rule 62C-26.003(4), Florida Administrative Code. The Department's Notice of Incompleteness. By letter dated March 26, 1997, the Department informed Coastal that the Twelve Applications were incomplete. The Department requested that Coastal provide additional information which it listed under eleven general categories: Location Plat; Environmental and Site Assessments; Zero Discharge; Accidental Pollutant Discharges; Drilling Platform; Hurricane Plan; Geologic Data; Transportation; Test Oil and Gas Plan; Drilling Plan; and H2S Contingency Plan. Coastal's Response to the Department's Notice of Incompleteness and Request for Additional Information. By letter dated September 22, 1997, Mr. Ware, on behalf of Coastal, responded to the Department's March 26, 1997, notice of incompleteness and request for additional information. In general, Coastal provided some of the requested information but indicated that it did not believe the Department had the authority to request most of the information. Therefore, Coastal informed the Department that most of the requested information was not being provided. Despite the fact that Coastal did not provide most of the requested information, Mr. Ware stated the following in the first paragraph of the September 22, 1997, letter: In fact, no statutory or regulatory authority was cited for any request. If Coastal is mistaken on any such request, please inform us of the specific authority allowing the department to require such information and Coastal will respond. [Emphasis added]. The Department's Answer to Coastal's Request for Specific Authority. Coastal's request for citations of specific authority and Coastal's representation that it would provide the information if such authority were given, was reasonably interpreted by the Department as an expression of Coastal's willingness to continue to discuss whether the Twelve Applications were in fact complete. As a consequence, the Department proceeded to respond to Coastal's request rather than proceeding to treat the Twelve Applications as complete and review them on their merits. After extensive research, the Department responded to Coastal's request for authority by letter dated December 16, 1997. The Department provided Coastal with citations to statutes and rules which the Department believed supported the additional information it had requested in its March 26, 1997, letter. See Coastal Exhibit 76. The Department also pointed out inconsistencies in the information Coastal had provided in support of the Twelve Applications. In particular, the Department asked why Coastal's H2S contingency plan referred to a drilling rig different than the one that Coastal had indicated it intended to use. The Department also asked Coastal how it planned to drill twelve wells within the time allowed after a permit is issued with only the one drilling platform that Coastal had indicated it planned to use for all twelve wells. Coastal's First Notice of Completeness. By letter dated December 26, 1997, Coastal informed the Department that it was not convinced that the authorities cited by the Department in its December 16, 1997, letter required that it provide the additional information sought by the Department. Mr. Ware, therefore, informed the Department in the December 26, 1997, letter of the following: As a result of the Department's insistence that Coastal provide such information, Coastal is left with no alternative but to file a petition for administrative hearing concerning whether the materials submitted by Coastal were sufficient to complete the applications so that they should have been processed by the Department. Twelve separate Petitions for Formal Administrative Hearing were filed by Coastal with the December 26, 1997, letter. Pursuant to the petitions, Coastal challenged the Department's request for additional information and sought approval of the Twelve Applications by default. Coastal's December 26, 1997, letter and the petitions filed simultaneously with the letter were the first indication from Coastal that it considered the Twelve Applications complete. On January 22, 1998, the Department entered an Order Dismissing Petitions, dismissing the twelve petitions filed by Coastal. The petitions were dismissed without prejudice to the filing of amended petitions alleging how the Department's December 16, 1997, letter constituted "agency action." No amended petitions were filed by Coastal. The Department also concluded in the Order Dismissing Petitions that Coastal's December 26, 1997, letter constituted Coastal's first notice that it considered the Twelve Applications complete and directed that staff grant or deny the Twelve Applications within 90 days from Coastal's notice. In support of the Department's conclusion that the Twelve Applications should not be considered as complete until Coastal filed its December 26, 1997, letter, the Department noted in its order that Coastal, in response to the Department's December 16, 1997, letter, had requested specific authority for the Department's request and had represented that it would provide the additional information sought by the Department if it were satisfied with authority cited by the Department. I. The Department's Denial of Coastal's Applications. On March 24, 1998, the Department entered a "Final Order" denying the Twelve Applications. It is this Final Order that is the subject of these proceedings. The Department's decision to deny the Twelve Applications was explained as follows: The applications as submitted do not provide the Department with assurance that the issuance of the permits would be in compliance with the standards and criteria of Chapter 377, Part I, F.S., and Rules 62C-25 through 62C-30, F.A.C. The Department cannot determine based on the information submitted, that the proposed drilling activities do not threaten public safety and the state's natural resources. Information critical to making such a determination remains absent. . . . The Department's Final Order denying the Twelve Applications was entered within 90 days after Coastal notified the Department that it did not intend to provide any additional information to support the Twelve Applications and that it considered the applications complete. The Department's decision to deny the Twelve Applications was based solely on the Department's conclusion that it had not been provided sufficient information to review the merits of the Twelve Applications. The Department's Specific Authority Over Oil and Gas Drilling Permits. Part I, Chapter 377, Florida Statutes (hereinafter referred to as the "Act"), establishes the law in Florida governing oil and gas resources of the State. Section 377.06, Florida Statutes, sets out the general public policy of the State concerning oil and gas: It is hereby declared to be the public policy of the state to conserve and control the natural resources of oil and gas in said state, and the products made therefrom; to prevent waste of said natural resources; to provide for the protection and adjustment of the correlative rights of the owners of the land wherein said natural resources lie and the owners and producers of oil and gas resources and the products made therefrom, and of others interested therein; to safeguard the health, property, and public welfare of the citizens of said state and other interested persons and for all purposes indicated by the provisions herein. . . . The Department is designated as one of the agencies of the State authorized to carry out the powers, duties, and authority of the Act. Section 377.07, Florida Statutes. The Department's authority includes the authority to adopt rules and enter orders it deems necessary to implement and enforce the provisions of the Act. Section 377.22, Florida Statutes. In particular, the Department has been given broad authority to regulate the drilling for oil and gas in Florida in Sections 377.22(2)(a) through (x), Florida Statutes. Pursuant to this broad authority, the Department has promulgated Chapters 62C-25 through 62C-30, Florida Administrative Code. Rule 62C-25.006, Florida Administrative Code, sets out the general rule concerning the exploration for oil and gas in Florida: Each person who conducts geophysical surveys (unless exempted by Rule 62C-26.007), drills an oil or gas related well (62C-26.003), or operates an oil or gas related well . . . (62C-26.008) shall first obtain a permit from the Department. Each of these activities requires a separate permit. [Emphasis added]. Ordinarily a single permit will be issued for drilling a well and either transporting test oil or injecting test fluids for a period of 90 days after testing is commenced. . . . In these cases, Coastal is seeking a permit to drill an oil or gas-related well and must, therefore, comply with Rule 62C-26.003, Florida Administrative Code, titled "Drilling Applications" (hereinafter referred to as the "Drilling Application Rule"). The Drilling Application Rule establishes certain specific requirements concerning specific information which, by the clear terms of the rule, must be provided by all applicants for oil and gas drilling permits in Florida. Applicants for drilling applications are required to be provide the following: All Applications to Drill (Form 3) shall include an Organization Report (Form 1; 62C- 25.008), performance security (62C-25.008, 62C- 26.002), location plat (62C-26.003(7)), site construction plans (62C-26.003(9)), casing and cementing program (62C-26.003(5)), contingency plan if appropriate (62C-27.001(7)), and application fee (62C-26.003(8)). In addition to these items, an application to drill a nonroutine well shall include a lease map or document and a letter of justification, both as described in 62C-26.004(6)(d). Any of these items already on file with the Department may be included by reference. The application to drill shall be considered incomplete until the applicant requests a preliminary inspection be made by the Department. . . . A proposed casing and cementing program must be included with the application to drill. This program shall at a minimum include setting depths, specified minimum yield strength, grade of pipe, class of cement to be used, cement additives, cement quantity, intended interval to be cemented, hole size, displacement method, special tools to be used, and calculated percent excess cement to be used. . . . . Each application shall be accompanied by a location plat surveyed and prepared by a registered land surveyor licensed under Chapter 472, FS. All such plats shall meet the minimum technical standards for land surveys as specified in Chapter 61G-17-6, FAC, and must: Be drawn to a scale sufficient to show the required detail, preferably 1 inch = 1,000 feet. Show and provide a legal description of all mineral acreage within the drilling unit which is not under lease to the applicant. Show the exact well location (both surface and bottom if different) and unit acreage within the drilling unit and indicate distances to adjacent wells, drilling unit boundaries, quarter-section corners, rivers and other prominent features. With prior notice and explanation to the Department, other established lines, reference points, or methods may be used when section corners are unavailable and an inordinate amount of preliminary surveying would have to be done to establish section corners or other standard reference points. In any case, a standard survey or equivalent with plat shall be made prior to obtaining an operating permit. Show ground elevation, with tolerances, at the drill site. State whether the proposed drilling unit is routine on nonroutine and specify the applicable subsection of s. 62C-26.004 under which the well is located. Each application to drill shall be accompanied by a $2,000 processing and regulatory fee . . . for costs incurred by the Department through well completion or plugging. . . . . . . . The applicant shall describe the provisions made for locating and constructing roads, pads, utility lines and other facilities needed for drilling operations and shall make every effort to minimize related impacts. Applications for permits in wetlands, submerged lands, and other sensitive areas shall be reviewed in accordance with 62C-30.005, FAC. Coastal provided all of the specific information applicable to the Twelve Applications required by the Drilling Application Rule. Much of the information required by the Drilling Application Rule, however, pertains to drilling operations on land and not drilling operations on submerged, offshore lands. The Department's Offshore Drilling Policy. Although Coastal provided all of the specific information required by the Drilling Application Rule, the Department required that a significant amount of additional supporting information be provided in support of the Twelve Applications. The additional information is generally described in Section E of this Recommended Order and is more specifically described, infra. Through the incompleteness letters issued by the Department in these cases, the Department expressed a statement of general applicability which "implements, interprets, or prescribes law or policy or describes the procedure or practice requirements of an agency . . . ." Section 120.52(15), Florida Statutes. The Department's statement of general applicability is, in effect, that all applicants for offshore oil and gas wells must provide the information described in the Department's letters of incompleteness to Coastal; information not specifically listed in the Drilling Application Rule. This state of general applicability will hereinafter be referred to as the "Offshore Drilling Policy." The Offshore Drilling Policy is of recent origin. It was not applied during the 1940's, 1950's, and 1960's. The policy was only recently developed because only a few offshore drilling permits have been applied for until recently and the technology applied in offshore drilling has changed significantly in the past fifty years. Between the 1960's and 1992, when Coastal filed five applications for permits, only one offshore drilling permit was issued by the Department. That permit was issued in the late 1970's or early 1980's to Getty Oil Company (hereinafter referred to as "Getty") for a test well approximately three miles offshore from Santa Rosa County, Florida. The Offshore Drilling Policy was not applied by the Department to Getty, although most of the information required in these cases was eventually provided by Getty. Getty provided the information not because of Department policy, however, but in an effort to settle a challenge to the Department's proposed decision to issue the permit. Although much of the Department's knowledge concerning offshore drilling was developed as a result of the Getty permit, the Department did not receive another permit application for offshore drilling for ten to twelve years or more. Since 1992, however, the Department has required the same additional information it requested Coastal to provide in these cases for seventeen different proposed well locations located from offshore sites off the northwest coast of Florida near St. George Island and extending to the southwest coast of Florida near Naples. The Offshore Drilling Policy has been adopted by the Department because existing rules were adopted primarily to govern drilling operations on land and not offshore. As a consequence, those rules inadequately address offshore wells. The Department, however, is charged with broad authority under Chapter 377, Florida Statutes, to govern oil and gas drilling operations on and offshore. That authority includes the broad authority to carry out the public policy of the State expressed in Section 377.06, Florida Statutes, to "conserve and control the natural resources of oil and gas . . . ; to prevent waste of said natural resources; . . . to safeguard the health, property and public welfare of the citizens . . . ." When the intent of existing rules is considered in the context of offshore drilling, it is apparent that Drilling Application Rule does not adequately address all the reasonable concerns with offshore drilling. The Department has developed the Offshore Drilling Policy to the point where it has become more than a mere interpretation and application of existing law to offshore drilling applications. The Offshore Drilling Policy has become a uniform statement of policy describing a significant amount of particular information which the Department will require for any application for an offshore drilling permit. The Offshore Drilling Policy has passed the point in its development that it can be considered the Department's reaction to a particular set of circumstances. The Scope of the Department's Application of the Offshore Drilling Policy. The Offshore Drilling Policy has been applied to the last seventeen applications for offshore wells filed with the Department. The first five applications were filed in March 1992. Although four of those applications were withdrawn, the Department developed the Offshore Drilling Policy and applied it to permit application 1281 prior to August 1996 when the Department issued its notice of intent to issue Permit 1281. Although the evidence failed to prove exactly when the Department decided to apply the Offshore Drilling Policy to permit application 1281, the policy had been applied before the Twelve Applications were filed in February 1997. The Offshore Drilling Policy was applied uniformly to the Twelve Applications from the date they were filed through the date of the hearing in these cases. The Offshore Drilling Policy was also sufficiently formulated for the Department to publish notice of its intent to adopt the Offshore Drilling Policy as a rule. That notice was published on November 24, 1998. Therefore, the Offshore Drilling Policy was sufficiently formulated to be proposed for adoption as a rule prior to the commencement of this de novo proceeding. It is apparent that the Department intends to apply the Offshore Drilling Policy to all applications for oil and gas wells proposed for location offshore in the waters of the State. At present, only Coastal has the right to drill in the sovereign submerged lands of the State and Section 377.242(1)(a)5, Florida Statutes, currently prohibits granting drilling permits within the boundaries of the Florida's territorial seas to any person other than Coastal. The evidence failed to prove, however, that Coastal cannot assign its right to drill to other persons, which it has done in the past. Even though Coastal may currently be the only applicant for oil and gas well drilling permits, the Department is at liberty to modify the Offshore Drilling Policy at any time to require different or additional information, without prior notice to Coastal. Coastal has the right to some certainty as to what information the Department may require for approval of an offshore drilling permit. Section 120.57(1)(e), Florida Statutes; De Novo Review of the Offshore Drilling Policy. Section 120.57(1)(e), Florida Statutes, requires a de novo review of any unadopted rule which formed the basis of any agency action. The Department's denial of the Twelve Applications in these cases was based solely on its application of the Offshore Drilling Policy. The Offshore Drilling Policy has not been adopted as a rule, although the Department has instituted rule- making procedures. Therefore, if the Offshore Drilling Policy constitutes a rule, the Offshore Drilling Policy must meet the requirements of Section 120.57(1)(e), Florida Statutes. Each category of information required by the Department pursuant to the Offshore Drilling Policy must be examined in determining whether some of the requirements of Section 120.57(1)(e), Florida Statutes, have been met. The other requirements of Section 120.57(1)(e), Florida Statutes, can be considered generally without an examination of each category of information required by the Department. Location Plat Information. The Department requested that Coastal provide the following information concerning the location of the proposed wells: For each proposed location, submit a plat on an original nautical chart showing each drilling site relative to the shore. This map should include at least the following surface and bottom hole locations including satellite navigation coordinates so the site can be re-occupied by a preliminary inspection team, boundaries of the working interest area, location of nearby reefs or sensitive aquatic wildlife areas, wildlife migration routes, proposed routing of supply ships, discharge barges, pipelines, helicopter routes, and commonly used shipping lanes. Also submit a diagram showing the orientation of the rig and the location of its major components. Coastal provided only standard nautical charts with a surveyed site location and the lease boundaries noted. The charts did not contain any of the information requested by the Department. Nor did the charts note whether the plotted points were surface or bottom hole locations. The Department relied upon the following authority in requesting the Location Plat information: Section 377.22(2)(h), Florida Statutes, and Rule 62C-26.003(7), Florida Administrative Code, quoted, supra. Section 377.22(2)(h), Florida Statutes, provides the following: (2) The department shall adopt such rules and regulations, and shall issue such orders, governing all phases of the exploration, drilling, and production of oil, gas, or other petroleum products in the state . . . as may be necessary for the proper administration and enforcement of this chapter. Rules, regulations, and orders promulgated in accordance with this section shall be for, but shall not be limited to, the following purposes: . . . . (h) To require the making of reports showing the location of all oil and gas wells; the making and filing of logs; the taking and filing of directional surveys; the filing of electrical, sonic, radioactive, and mechanical logs of oil and gas wells; if taken, the saving of cutting and cores, the cuts of which shall be given to the Bureau of Geology; and the making of reports with respect to drilling and production records. . . . The Department's purpose in requiring the information concerning the Location Plat was to allow it to place the proposed drilling site into context with the surrounding environmental and other features of the area. Without the requested information, the Department could not ensure that sensitive resources and significant features would not be damaged by the proposed drilling operations. Rule 62C-26.003(7), Florida Administrative Code, does not directly authorize the Department to request the Location Plat information. That rule was drafted with onshore drilling operations in mind. Requiring the Location Plat information in these cases is not a mere application of that rule. Rule 62C-26.003(7), Florida Administrative Code, however, does support the conclusion that the requested information is needed for offshore, as well as onshore drilling. More importantly, it demonstrates the broad authority of the Department under the Act to require assurances from an applicant for offshore drilling that the proposed drilling will not be detrimental to the environment. The information provided by Coastal concerning archaeological sites, underground sea cables, and sensitive environmental features on the bottom was not sufficient for the Department to fulfill its responsibilities under the Act. The Act in general and the specific cites provided by the Department in support of its request for Location Plat information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting Location Plat information was not arbitrary or capricious. Environmental and Site Assessment. The Department requested that Coastal provide the following information concerning environmental features of the proposed well sites: Submit a professional ecological/biological survey and report for each proposed drill site. Wildlife habitats including living coral reefs, artificial reefs, patch reefs, benthic infauna, sea grasses, and associated communities shall be identified and located if present. Photodocumentation consisting of television and color still photography shall be included with each report. . . . The Department's request included an outline format for the photodocumentation survey report. Coastal provided no information in response to the Department's request for Environmental and Site Assessment information. Instead, Coastal suggested that the Department obtain the information it requested through the preliminary site inspection required by the Department's rules. The Department relied upon the following authority in requesting the Environmental and Site Assessment information: Sections 377.21(2), 377.22(2)(i), 377.241(1), and 377.371(1), Florida Statutes, and Rule 62C-26.003(10), Florida Administrative Code. While Section 377.21(2), Florida Statutes, gives the Department little authority concerning the protection of the environment, the other statutory provisions cited by the Department do. Section 377.22(2)(i), Florida Statutes, authorizes the Department to take into consideration the impact of drilling operations on surrounding leases or property. Section 377.241(1), Florida Statutes, requires the Department to take into consideration the nature, character, and location of lands on which drilling will occur and those involved with the drilling. Finally, and most significantly, Section 377.371(1), Florida Statutes, requires that drilling not cause pollution to land or water, "damage aquatic or marine life, wildlife, birds, or public or private property " Rule 62C-26.003(10), Florida Administrative Code, provides, in part, that "[a]pplications for permits in . . . submerged lands, and other sensitive areas shall be reviewed in accordance with 62C-30.005," a rule governing applications for drilling in the Big Cypress Watershed. Rule 62C-30.005(2)(b), Florida Administrative Code, sets out the requirements for drilling sites. Among other things, Rule 62C-30.005(2)(b)2, Florida Administrative Code, requires that topographical and engineering surveys of the drill site, along with aerial photography, must be prepared. While this rule does not specifically authorize the Environmental and Site Assessment information the Department has requested, the statutory authority that supports the rule does. Aerial photography is normally required as an aid to the Department in identifying the proposed site and the surrounding area. Obviously, aerial photography would be of little assistance for a submerged site. Therefore, in order for the Department to carry out its responsibility to protect the environment, including sensitive environmental features such as "live bottom areas" as defined in Rule 62C-25.002(49), Florida Administrative Code, the Department requested photodocumentation of the proposed sites. The Department's request that Coastal provide it with an environmental assessment of the proposed drilling sites was also made to give the Department the necessary information for it to ensure that the environmental impacts of the proposed wells would not be detrimental. Such information also relates to the ability of an applicant to ensure that it has adopted adequate plans to deal with possible oil spills and other accidents. By fully considering the environmental features of an area, the applicant will be better able to draft and adopt contingency plans. Unlike onshore drilling, an offshore well entails a relatively large drilling rig with large feet that rest on the bottom to support the drilling platform above the surface of the water. Those feet, if placed on live bottom, can cause significant damage to marine biota which live in crevices, cracks, and permeable portions of some rocks that may be found on the bottom. The preliminary site inspection conducted by the Department is not an adequate substitute for the information requested by the Department. That inspection is only intended to verify the assurances which the applicant is first required to give. After all, it is the applicant that is seeking permission to drill. As a consequence, the applicant should first determine what impact its proposed drilling will have and, if satisfied on its findings, provide assurances to the Department to support its application. The Act in general and the specific cites provided by the Department in support of its request for Environmental and Site Assessment information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting Environmental and Site Assessment information was not arbitrary or capricious. Zero Discharge. The Department requested that Coastal provide the following information concerning a "zero discharge" plan for the proposed wells: Submit a plan which ensures zero discharge operation for each proposed well. The plan must include an environmental monitoring plan which provides for filed sampling around the drill site such that pre-drilling, drilling, and post- drilling sediments may be compared. Coastal, in response, only stated that it intended to use a zero discharge drilling rig at all the proposed sites. A copy of a brochure generally describing the rig was provided. No description of systems for containing discharges was provided. Nor did Coastal provide monitoring and sampling plans. The Department relied upon the following authority in requesting a zero discharge plan: Sections 377.21(2), 377.22(2), 377.22(2)(c) and (i), 377.241(1), 377.243, 377.371, and 377.371(1), Florida Statutes, and Rule 62C-26.003(10), Florida Administrative Code. A zero discharge plan is the written plan that an applicant is supposed to follow in the event of the discharge of any pollutant into the surrounding environment of a well site. The plan must cover not only discharges from the well shaft, but also from all equipment used, located, or traveling to the site. The purpose of the plan is to prevent spills and, where an accidental spill occurs, to minimize the impact of the spill. While the use of a zero discharge rig may be a significant part of a zero discharge plan, its use alone is not sufficient. The use of zero discharge rig does not provide assurances concerning the operation of other vessels and equipment which may be used at a site. Nor does its use provide assurances as to what will be done to ensure that the rig works properly or what will be done if it does not. Section 377.22, Florida Statutes, provides authority for the Department to ensure that all precautions are taken to prevent pollutants entering the area of a drilling site or any area associated with the well. Section 377.22(2)(a), Florida Statutes, authorizes the Department to require that drilling operations are done in such a manner as to prevent pollution of the waters, including salt water, and property of the State. Section 377.22(2)(c), Florida Statutes, authorizes the Department to require safety equipment to minimize the possibility of an escape of oil and other petroleum products. Finally, Section 377.22(2)(i), Florida Statutes, authorizes the Department to prevent drilling operations that will cause injury to neighboring property. Section 377.243(2), Florida Statutes, also provides the Department with the authority to require assurances concerning an applicant's efforts to protect against discharges into the environment of oil and other pollutants: (2) As a condition precedent to the issuance or renewal of a permit, the division shall require satisfactory evidence that the applicant has implemented or is in the process of implementing, programs for control of pollution related to oil, petroleum products or their byproducts, and other pollutants and the abatement thereof when a discharge occurs. Finally, Section 377.371(1), Florida Statutes, prohibits persons drilling for oil and gas from polluting land or water and from damaging marine or aquatic life. A spill of oil or gas and other pollutants can have a devastating impact on the environment regardless of whether the spill occurs on land or at sea. Such damage could result in loss of tourism in Florida and severe economic damage. The oil industry has progressed significantly in its ability to prevent spills and, where spills occur, to minimize the impacts of the spill on the environment. In order to minimize the chance of spills and the impacts which could occur from a spill, however, an applicant must take the steps necessary to plan ahead of time and provide the Department with the assurances that the applicant has done so. The Act in general and the specific cites provided by the Department in support of its request for zero discharge information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting zero discharge information was not arbitrary or capricious. Accidental Pollutant Discharges. The Department requested that Coastal provide a spill contingency plan for each of the proposed well sites. The requested plan was to include Coastal's plans for dealing with escaped pollutants, modeling of how projected spills might react, plans for deployment of cleanup equipment, inventories of equipment available for dealing with spills, designation of the individuals responsible for cleanup, and general clean-up plans. In response to the request for the spill contingency information the Department insisted it needed, Coastal stated the following: With respect to Coastal's implementation of a program for control of pollution related to oil, petroleum products and their byproducts, and other pollutants, see the letter of Dr. Tom Herbert, and his curriculum vita, as well as the ISO 14,000 Program on file in Permit #1296. With respect to Coastal's implementation of a program for the abatement of pollution discharges related to oil, petroleum products and their byproducts and other pollutants, see attached letter of Shaw Thompson, and his resume on file in Permit #1296. Coastal did not provide the Department with a specific, written oil-spill contingency plan. Dr. Herbert was involved with ensuring compliance of the Getty well off of Santa Rosa County with environmental protection requirements. Dr. Herbert had not, however, reviewed information concerning the Twelve Applications other than the nautical charts showing the location of the wells. In a letter from Dr. Herbert submitted by Coastal to the Department, Dr. Herbert represented the following concerning Coastal's proposed operations: Coastal Petroleum has used the Getty operations as a "template" for designing operations for the permit number 1281 well and for all subsequent drilling permits pending (numbers 1296 through 1307). We have been retained to assist with the development of plans and procedures and to insure that the operations are carried out in an environmentally safe and conscientious manner. . . . . Coastal Petroleum Company has adopted the ISO 14000 standard as the method for implementing long-term environmental compliance for drilling and production operations off Florida's coast. As the issuance date for the 1281 permit draws near we will begin implementing the ISO 14000- program beginning with training provided by the University of Florida TREEO Center. The implementation of the environmental program will extend from Coastal's own employees to others who may be service companies or contractors. Dr. Herbert's representations to the Department in his letter and at hearing do not constitute an actual oil-spill contingency plan for any of the specific proposed well sites. At best, his representations constitute a commitment to deal with the manner in which Coastal will comply with environmental requirements in the future. It does not constitute a commitment to actually draft and implement an oil-spill contingency plan. Dr. Herbert and Coastal also failed to explain how the Getty site, which was located in 11 to 12 feet of water, is sufficiently similar to the proposed sites of the Twelve Applications, which are all located in much deeper waters. Nor did Coastal explain how it would deal with the fact that the Getty site was not in the open waters of the Gulf of Mexico. More importantly, no specific oil-spill contingency plan was provided for the twelve proposed sites. Mr. Thompson is an expert in oil-spill containment and cleanup. Coastal provided a letter from Mr. Thompson providing assurances that he would be working with Coastal during any drilling of the twelve proposed wells. At hearing, Mr. Thompson had little knowledge of the proposed sites. More importantly, Mr. Thompson did not provide a specific oil-spill contingency plan for the twelve proposed sites. The ISO 14000 Guide provided by Dr. Herbert consists of a book containing a generic template suggested by the author for use by any business concerned with environmental impacts. The Guide is not specific to the oil and gas industry. More importantly, it is not specific to Coastal nor any of the proposed well locations. Finally, the Guide would be of little assistance in dealing with an actual emergency. The Guide is not a specific oil-spill contingency plan. The Department relied upon the following authority in requesting the oil-spill contingency plan: Sections 377.22, 377.22(2)(c), 377.243, and 377.371, Florida Statutes. The same statutory authority that supports the request for a zero discharge plan, supports the oil-spill contingency plan requested by the Department. Especially Section 377.243(2), Florida Statutes, quoted, supra. While Section 377.243(2), Florida Statutes, allows an applicant to implement or be in the process of implementing an abatement program, merely indicating the intent to implement a program is insufficient. The Department must ensure that an applicant has taken sufficient steps to prevent the pollution of land or water, as well as damage to aquatic or marine life, wildlife, and birds. The environmental damage from a spill or a well blow-out can be significant. One of the worst oil well blow-outs occurred at an exploratory well. Site specific information must be considered by the applicant in its planning and such information must be provided to the Department for it to make its statutorily required evaluation. The Act in general and the specific citation provided by the Department in support of its request for an accidental pollutant discharge plan give the Department sufficient authority to request the plan. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting the accidental pollutant discharge plan was not arbitrary or capricious. Drilling Platforms. The Department requested that Coastal provide information concerning the drilling platform(s) Coastal intended to use at each proposed site. In particular, the Department requested information concerning rig impacts, rig designation, scheduling, commitment from rig owners, zero discharge, auxiliary power equipment, and safety plans concerning karst hazards, including a shallow seismic program to rule out the existence of sinkholes or bottom caverns. In response to the request for the drilling platform information the Department sought, Coastal provided only a brochure for the Nobel Drilling Company's rig, the Paul Wolff. Coastal also indicated that the rig would face north. The Department relied upon the following authority in requesting the drilling platform information: Sections 377.22(2)(c), (d), and (i), Florida Statutes; and Rules 62C- 26.003(10), 62C-27.001(4), (5), (6) (cited as 62C-26001(5) and 62C-26001(6) by error in the Department's December 16, 1997, letter), and 62C-28.004(8), Florida Administrative Code. Section 377.22, Florida Statutes, provides authority for the Department to ensure that all precautions are taken to prevent pollutants entering the area of a drilling site and to protect surrounding property. Section 377.22(2)(a), Florida Statutes, authorizes the Department to require that drilling operations are done in such a manner as to prevent pollution of the waters, including salt water, and property of the State. Section 377.22(2)(c), Florida Statutes, authorizes the Department to require safety equipment to minimize the possibility of an escape of oil and other petroleum products. Section 377.22(2)(d), Florida Statutes, authorizes the Department to ensure that drilling is performed in a manner that will prevent the escape of oil from one stratum to another. Finally, Section 377.22(2)(i), Florida Statutes, authorizes the Department to prevent drilling operations that will cause injury to neighboring property. The rig Coastal proposed to use sits on three large feet, each with a diameter of over 93 feet. Each foot sits 235 feet from the other two. The entire rig is extremely heavy and, therefore, each foot has a great deal of weight placed on it. The Department requested information concerning rig impacts in order to avoid adverse impacts on the sea bottom. The Department requested information on rig designation, scheduling and owner commitment because of the Department's concern that a single rig could not drill all twelve wells within the limited one-year period of time a permit is valid for. Coastal had also provided some inconsistent information in its hydrogen sulfide plan concerning what rig would be used. Without knowing what rig would be used at each location, the Department could not fully evaluate the possible impacts of the rig on the environment. The seismic survey and the sink hole and karst formation safety plans were requested because of concerns that a rig could collapse if it were placed on such a formation. A karst formation is a geologic formation caused by increased porosity and permeability of underground limestone formations. As limestone is eaten away, the potential for a sinkhole or cavern collapse increases. Sinkholes and karst formations are not uncommon in the area of Coastal's proposed wells. If a rig collapsed on a karst formation, it is possible that a blow out or other oil spill could occur. The potential for such a catastrophe is greater in this instance because the rig that Coastal is proposing to use is a tripod design which could tip over if one foot were placed in a sinkhole or karst formation that collapses. A shallow seismic survey would provide information concerning possible karst formations at the sites where Coastal plans to drill its test wells. The Act in general and the specific cites provided by the Department in support of its request for rig impact information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting rig impact information was not arbitrary or capricious. Hurricane Response Plan. The Department requested that Coastal provide a hurricane preparation and response plan for each site. Coastal provided none of the requested information. The Department relied upon the following authority in requesting the hurricane response plan: Section 377.22(2)(c), Florida Statutes, and Rules 62C-27.001(5) and 62C-27.006(1), Florida Administrative Code. Section 377.22(2)(c), Florida Statutes, authorizes the Department to require safety equipment to minimize the possibility of an escape of oil and other petroleum products in the event of a natural disaster. Although not cited by the Department, Section 377.371, Florida Statutes, gives the Department broad authority to ensure that oil and gas wells do not pollute. The entire area where Coastal proposed to drill is subject to hurricanes for a significant part of every year. Such storms can have a devastating impact on any structure, including an oil rig, which is in its path. Requiring that an applicant for drilling permits anywhere in the coastal waters of Florida plan ahead of time to respond to an approaching hurricane is abundantly reasonable. The Act in general and the specific citation provided by the Department in support of its request for a hurricane preparation and response plan give the Department sufficient authority to request the plan. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting a hurricane preparation and response plan was not arbitrary or capricious. Geologic Data. The Department requested that Coastal provide the following information concerning the geology of each location of its proposed well sites: Submit material in the form of studies, data, cross sections, or maps which support or explain your decision for locating each well as proposed. All interpreted geologic data must be certified by a geologist licensed in Florida. Coastal provided none of the requested information. For applications 1296 and 1297, Coastal referred the Department to its application for Permit 1281. The Department relied upon the following authority in requesting the geologic information: Section 377.075(4)(g), 377.21(2), and 377.241(3), Florida Statutes, and Rule 62C- 26.004(6)(d), Florida Administrative Code. Section 377.075(4)(g), Florida Statutes, requires that the Department maintain maps identifying information concerning oil and gas activities in Florida. This provision does not, however, authorize the Department to request the geologic information it requested from Coastal. Section 377.21(2), Florida Statutes, gives the Department the authority and the duty to make inquiries to determine whether "waste" exists or is imminent. "Waste" is defined in Section 377.10(10), Florida Statutes. Based upon the definition of "waste," Section 377.21(2), Florida Statutes, gives the Department the authority to request the information it requested concerning the geology of Coastal's proposed locations. Finally, Section 377.241(3), Florida Statutes, requires that the Department take into consideration the "proven or indicated likelihood of the presence of oil, gas or related minerals in such quantities as to warrant the exploration and extraction of such products . . ." before issuing any permit. This provision alone is sufficient for the Department to request the geologic information it requested from Coastal. Oil and gas wells are not drilled without first considering the geology of an area and the likelihood that oil or gas may be found. The determination of a likely successful well is made by a consideration of relevant geologic information such as that requested by the Department. Without such information, the Department would not be able to reasonably carry out its duty under Section 377.231(3), Florida Statutes. Coastal did not dispute the reasonableness of the requested information in determining whether a well should be placed at a proposed location. Instead, Coastal suggested that the Department has all the information it needs to make the determination and, therefore, Coastal shouldn't be required to provide any further information. The information available to the Department, however, is too general in nature. It does not deal with specific locations such as those proposed by Coastal. More importantly, it is Coastal that is seeking permission to drill. Coastal should, therefore, have already gathered and considered the geologic information requested by the Department in deciding where to place its exploratory wells. There have been relatively few wells drilled in Florida offshore waters. None have been productive. One offshore well located near Franklin County was drilled in 1968 and was dry. The only producing offshore well was located off the southern tip of the Florida Keys. Given these facts, the Department was reasonable in seeking assurances from Coastal concerning the possibility that its proposed wells were reasonably placed. Finally, the information Coastal referred to with regard to Permit 1281 was submitted during the formal administrative hearing on that case and was not as part of Coastal's permit application. That information, therefore, was not available to the Department to review. Nor was it provided during the formal hearing on these cases. The Act in general and the specific cites provided by the Department in support of its request for geologic information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting geologic information was not arbitrary or capricious. Transportation. The Department requested that Coastal provide the following information concerning transportation to and from the proposed wells of the drilling rig(s), a description of onshore facilities and the traffic to the rig(s), and a description of, and route to be taken by, transport vessels and helicopters. In response to the Department's request for the transportation information demanded by the Department, Coastal merely stated that no helicopters would be used at any of the proposed sites except in case of an emergency. The Department relied upon the following authority in requesting information concerning transportation: Section 377.22(2)(s), Florida Statutes, and Rules 62C-26.006(1) and 62C- 26.003(10), Florida Administrative Code. Section 377.22(2)(s), Florida Statutes, allows the Department to require "certificates of clearance or tenders in connection with the transportation or delivery of oil or gas, or any product." Section 377.371, Florida Statutes, authorizes the Department to ensure that a drilling operation is not harmful to the environment. This provision alone gives the Department sufficient authority to request information from Coastal concerning how it intends to deal with transportation issues concerning the proposed wells. Pursuant to the Department's statutory authority, the Department has adopted Chapter 62C-30, Florida Administrative Code, which, among other things, provides rules governing transportation issues for wells located in Big Cypress. Although those rules do not specifically deal with offshore wells, they do support the conclusion that assurances concerning transportation issues surrounding any well can be required by the Department. Accidents, and the resulting damage to the environment, often occur during the transportation of oil and other equipment and supplies used for a rig. The Department needs to be provided with assurances that every effort is made by an applicant to avoid such damage. If provided sufficient information, the Department may be able to require that an applicant use a different route between a rig and an onshore facility in order to avoid a sensitive reef and thereby reduce the potential adverse impacts of an accident to the reef. A different route may also be required due to safety concerns. In addition to the legitimate concerns of the Department about accidental spills of oil, gas, and cuttings, the Department is concerned about the transportation of other noxious or hazardous materials used in drilling operations. Mixed saltwater and oil byproducts of drilling also must be transported away from a well site. Spills of these materials can have adverse impacts on the environment and, therefore, steps must be taken to reduce those impacts. The Act in general and the specific citations provided by the Department in support of its request for transportation information give the Department sufficient authority to request the information. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting transportation information was not arbitrary or capricious. Test Oil and Gas Plan. The Department requested that Coastal provide the following information concerning plans to test for oil and gas at each of the proposed wells: Submit a plan for safely producing, transporting, and storing test oil and gas. What mode of transportation is anticipated? Tankers? Barges? Pipelines? Where will produced test oil/gas be taken? Where will landfall occur? Include a statement from each appropriate local government assuring that all proposed facilities for oil and gas transportation and storage, both onshore and offshore, will be in compliance with local comprehensive plans. Indicate any leasehold interest or other property interests which will need to be secured to transport test oil or gas. Will test gas be vented, flared, or stored? Discuss why. Coastal provided no test oil and gas plan or other information in response to this request. The Department relied upon the following authority in requesting the test oil and gas plan: Sections 377.06, 377.22(2)(c) and (s), Florida Statutes, and Rules 62C-25.006(1) and 62C-28.001, Florida Administrative Code. For all the reasons previously discussed concerning the Department's authority to regulate oil and gas wells, the Department's statutory authority is broad enough to require the test oil and gas plan it requested from Coastal. The testing of fluids, their transport, and their storage all can have adverse impacts on the environment. The Act in general and the specific citations provided by the Department in support of its request for a test oil and gas plan give the Department sufficient authority to request the plan. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting a test oil and gas plan was not arbitrary or capricious. Drilling Plan. The Department requested that Coastal provide information concerning drilling plans for the proposed wells, including a blow-out prevention plan. In response, Coastal provided all of the requested information, including a casing plan, cementing plan, and drilling plan, but refused to provide a blow-out prevention plan. The Paul Wolff brochure provided to the Department included a list of blow-out preventers that are standard equipment on the rig, but there was no information concerning how a blow-out would be dealt with. The Department relied upon the following authority in requesting the blowout prevention plan: Sections 377.22(2)(a), (c), (d), (e) and (l), Florida Statutes, and Rules 62C-26.003(5), 62C-26.007, and 62C-27.005, Florida Administrative Code. Section 377.22(2)(l), Florida Statutes, authorizes the Department to adopt rules to prevent blow-outs. That authority, coupled with other provisions of the Act giving the Department the authority to protect the environment from oil and gas well drilling operations, is sufficient authority for the Department to require the requested blow-out prevention plan. A blow-out can cause the release of oil and gas into the environment with serious consequences to the environment. Preventing a blow-out is, therefore, of paramount importance. Proper prevention of blow-outs depends upon the geology of each drilling site. Different sites may require different equipment or different measures to prevent a blow-out. Consequently, a separate plan for each site is reasonable and necessary. The Act in general and the specific citations provided by the Department in support of its request for a blow-out prevention plan give the Department sufficient authority to request the plan. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting a blow-out prevention plan was not arbitrary or capricious. H2S Contingency Plan. The Department requested that Coastal provide a hydrogen sulfide (H2S) contingency plan, including a site specific air dispersion model for each site predicting the transport of any hydrogen sulfide accidentally released into the air. Coastal provided a single hydrogen sulfide contingency plan. No air dispersion modeling was provided. The Department relied upon the following authority in requesting individual plans and modeling: Sections 377.22 and 377.243(2), Florida Statutes, and Rule 62C-27.001(7), Florida Administrative Code. Hydrogen sulfide is a toxic gas which can be released during drilling operations. The gas is colorless. It is also denser than air. If not handled properly, a release can be fatal to anyone coming into contact with the gas. For an offshore well, a release of hydrogen sulfide can injure workers on the rig and boaters or fishermen in the area. Contact with hydrogen sulfide at a concentration of 100 parts per million can kill a person's sense of smell in 3 to 15 minutes. At a concentration of 300 parts per million, it can be fatal, and at 500 parts per million breathing will cease in only a matter of a few seconds. Because hydrogen sulfide is heavier than air, it will remain just above the surface of the water, where people are normally located on the Gulf. Individuals on the Gulf cannot escape to higher ground to avoid the gas like they may be able to do on land. While modeling cannot provide certainty as to how a cloud of hydrogen sulfide might act, it can at least give information concerning the prevailing wind direction of each site, which may be beneficial in being prepared to deal with an accident. Without such information it is difficult to determine whether plans to deal with an accident are adequate. Section 377.243(2), Florida Statutes, provides adequate authority for the Department to require that Coastal provide modeling for each proposed site. The Act in general and the specific citations provided by the Department in support of its request for hydrogen sulfide modeling give the Department sufficient authority to request the modeling. The Department's request did not enlarge, modify, or contravene its grant of authority. The Department's exercise of its authority in requesting modeling was not arbitrary or capricious. Section 120.57(1)(e)2.c., Florida Statutes. None of the required information is vague, establishes inadequate standards, or vests unbridled discretion in the Department. All of the information requested by the Department was understood by Coastal. Coastal knew what the Department was requested because it had already provided the requested information in support of its 1281 permit application. Section 120.57(1)(e)2.e., Florida Statutes. Coastal received adequate notice of the Department's Offshore Drilling Policy. Coastal had been requested to provide the information in support of its 1281 permit application. It was given written notice of the Offshore Drilling Policy in these twelve cases through the March 26, 1997, notice of incompleteness and the December 16, 1997, explanation of authority for the requested information. AA. Section 120.57(1)(e)2.g., Florida Statutes. While there are costs which Coastal would be required to pay in order to provide the information required by the Department, those costs are not excessive; not when the rationale for requesting the information is considered. Coastal did not consider the costs associated with providing the information sought by the Department to be too excessive for it to refuse to provide the information in seeking Permit 1281. On the contrary, Coastal incurred those costs. Although there was testimony that the costs of providing the information for Permit 1281 was in excess of a million dollars, the weight of the evidence failed to support the testimony. The evidence proved that the costs of providing all of the information requested by the Department would be well below a million dollars for each well. As to considering less costly alternatives, Coastal never gave the Department an opportunity to do so. Coastal simply refused to provide the requested information, to propose less-costly alternatives, or to discuss the matter further with the Department. Nor were any, less costly, methods of obtaining the information necessary for the Department to carry out its responsibilities under the Act proved at hearing.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department of Environmental Protection enter a Final Order denying permit applications 1296 through 1307 for failure to file complete applications. DONE AND ENTERED this 26th day of March, 1999, in Tallahassee, Leon County, Florida. LARRY J. SARTIN Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 26th day of March, 1999. COPIES FURNISHED: Robert J. Angerer, Esquire Robert J. Angerer, Jr., Esquire Angerer and Angerer Post Office Box 10468 Tallahassee, Florida 32302 Andrew Baumann, Assistant General Counsel John W. Costigan, Deputy General Counsel Department of Environmental Protection Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Monica K. Reimer, Assistant Attorney General Department of Legal Affairs The Capitol, Plaza Level 01 Tallahassee, Florida 32399-1050 S. Ansley Samson, Esquire David G. Guest, Esquire Earthjustice Legal Defense Fund Post Office Box 1329 Tallahassee, Florida 32302 Kathy Carter, Agency Clerk Department of Environmental Protection Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 F. Perry Odom, General Counsel Department of Environmental Protection Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 David B. Struhs, Secretary Department of Environmental Protection 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000
Findings Of Fact Puckett Oil Company, at times pertinent hereto, operated a full-service gasoline and auto service station at 7251 Pensacola Boulevard, Pensacola, Florida. The station at that site performed a complete range of automotive repairs, including lubrication and oil changes. These services are typical of such full-service service stations. On or about June 27, 1986, the operator of that station which was owned by Puckett, Mr. Winters, discovered a discharge of used oil at the site. The discharge occurred because the operator believed that used oil had been drained into an underground storage tank on a routine basis at the facility, as the oil was changed in customer vehicles. In fact, it developed that, unbeknownst to Mr. Winters, the tank had been removed by the prior land owner. This resulted in repetitive contamination of soil and groundwater at the facility, since the oil poured into the floor drain at the station, after being removed from the crank cases of customer vehicles, was in reality draining into the ground, instead of into a storage tank. After becoming aware of this problem, Puckett filed an Early Detection Incentive (EDI) Program Notification Application, reporting the discharge of used oil to the Department, pursuant to Section 376.3071, Florida Statutes (Supp. 1986). That EDI notification application form lists used oil as a "product." Puckett notified the Department of its intent to proceed with voluntary cleanup at the Puckett site pursuant to Section 376.3071(11) and (12), Florida Statutes (Supp. 1986), and to seek reimbursement for the cost of that contamination cleanup pursuant to Section 376.3071(12), Florida Statutes (Supp. 1986). The Department, in view of the request, conducted a site inspection on December 19, 1986. The Department's inspection personnel prepared an EDI Program Compliance Notification Checklist on the Puckett site. This report noted the circumstances of the discharge, to the effect that the used oil tank had been removed while used oil was still being disposed of through the drain at the service station. Thereafter, by its Order of April 16, 1987, the Department advised Puckett that its site was not eligible for "Super Act" reimbursement. The denial of eligibility was based on the DER's position that used oil was not "petroleum" or a "petroleum product" for purposes of Section 376.301(9) or (10), Florida Statutes (Supp. 1986). On May 8, 1987, Puckett filed a Petition for Formal Proceedings, alleging, among other things, that used oil is "petroleum" or "petroleum product" within the meaning of the "Super Act" and that the Department is estopped from denying "Super Act" reimbursement eligibility for voluntarily reported discharges of used oil. Inasmuch as the DER conducted inspections of the site in question, recording its findings, the Department was aware of the circumstances of the discharge; that the used oil tank had been removed and that oil had continued thereafter to be placed in the drain facility, thus contaminating the soil where the used oil disposal tank had formerly been placed. The Department did not raise the eligibility exception involving gross negligence in the Order of April 16, 1987, however, nor by any other vehicle until the filing of its Motion for Continuance with the Hearing Officer on August 31, 1987. Additionally, in response to a Request for Admissions served by Puckett, the Department admitted that the sole basis for denial of the reimbursement eligibility for the Puckett site was the fact that the substance discharged was "used oil," which the Department contends is not petroleum or petroleum product and thus is not a proper subject for reimbursement of related clean up and decontamination expenses. Uncontroverted evidence establishes that in August 1984, eleven oil changes at the Puckett site generated 3.5 quarts or about 9 1/2 gallons of used oil. Using this figure as an average, until the time the discharge was discovered 22 months later, the Puckett site generated approximately 210 gallons of used oil. Mr. Winters testified that he believed he had a 500 or 1,000 gallon used oil tank. Puckett's used oil was disposed of by inserting the drain bucket on the floor drain. The floor drain is a receptacle with an adapter on it for the oil drain bucket. Although the floor drain system appeared to be a working system, the underground used oil storage tank at the Puckett site had been removed, unbeknownst to Mr. Winters. It was apparently removed by Exxon Corporation, the previous site operator. It was Exxon's practice to remove fuel tanks from non-operational stations, such as the Puckett site was at the time it was sold to Puckett. It was not their normal practice, however, to remove used oil storage tanks. Mr. Winters, in his sixteen years of operating service stations, has never experienced a floor drain with such an adapter that was not connected to an underground storage tank. Further, he had previously leased a service station that had been purchased from Exxon after being closed for seven years and the used oil tank was still in place at the time he took possession of the station. He asked the person responsible for closing the Exxon station (the Puckett site) where the used oil tank was located. That person responded by pointing to an area of landscape shrubbery where a galvanized pipe could be seen protruding from the ground. A used oil collection company attempted to pump the contents of the tank using that pipe. Three large holly bushes were growing undisturbed over the area where Mr. Winters had been told the tank was located. It thus appeared to Mr. Winters that the tank could not have been removed. There was no evidence that Mr. Winters attempted to conceal the discharge of the oil or that he continued to dispose of the used oil in the floor drain after discovering that the tank had been removed. If the floor drain had not become stopped up, Mr. Winters likely never would have begun looking for the presence of the tank. A used oil collection company never was able to pump any used oil from the pipe supposedly connected to the tank. It was Mr. Winters' belief that used oil collection companies normally came to service stations after closing hours to pump the used oil storage tanks, so they can avoid paying for the used oil. It was for this reason, he believed, that he rarely had seen a used oil collection company trying to pump oil from such a storage tank. He was thus not concerned when the company reported that it could pump no used oil from the tank because he believed that another used oil collector had previously drained it. The used oil discharged at the Puckett site consists of used engine crank case oil with an estimated two percent of used transmission oil. Used oil at the Puckett site is not mixed with solvents or other hazardous wastes. Puckett does not accept neighborhood collections of used oil. An assessment of the contamination at the Puckett site was conducted by Delta Environmental Consultants. Delta had an analysis of soil samples prepared by Pioneer Laboratories and an analysis of ground water samples by Savannah Laboratories. Dr. Litt, the Petitioner Puckett's expert witness, opined, based on the contamination assessment, that the contamination was due to used oil or "used oil fuel" instead of "hazardous waste fuel" or hazardous waste. Dr. Litt relied on the testimony of Mr. Winters to the effect that solvents or other hazardous wastes were not mixed with the used oil at the Puckett site in the service station's operations. Based on the soil and ground water analyses supplied him, Dr. Litt found an absence of halogenated solvents which would commonly be mixed with used oil, thus corroborating Mr. Winters' testimony that the used oil at the Puckett facility was not known to have been mixed with any hazardous wastes. The soil analysis indicates a level of organic halogens of 1,090 parts per million. This level might raise a presumption, under relevant EPA regulations, that the oil had been mixed somewhat with hazardous wastes, but Dr. Litt established that indeed no mixing had occurred based upon Mr. Winters' testimony, as well as the fact that the testing method used is accurate to only a plus or minus 700 parts per million in a total range of 1,000 to 2,000 parts per million. Indeed, some halogen levels may be attributed to natural soil conditions. Thus, the finding of 1,090 parts per million organic halogens could be as much as 700 parts per million in error, and some of this quantity can be due to natural backgrounds. Additionally, the level of individual chlorinated solvents sampled indicated no mixing of used oil with typical hazardous wastes. International Petroleum Corporation International Petroleum Corporation (International) has operated an oil storage plant and used oil reclamation facility at 105 South Alexander Street, Plant City, Florida, since May 1980. That site contains approximately 10 acres. There are two on-site tank farms containing 17 above-ground stationary tanks and two underground tanks. One underground tank holds 10,000 gallons and is used to store diesel fuel. The other tank holds 5,000 gallons and stores virgin gasoline. The above-ground tanks range in size from 8,000 to 212,000 gallons and are used to store oil, both used oil and new oil. All the tanks have been registered with the DER in accordance with its rules and are a part of the DER's "stationary tank system." The plant site also contains an office building and a testing laboratory which provides an array of testing services. The lab contains an atomic absorption unit, kinematic viscosity baths, API gravity hydrometers, distillation equipment and a gas chromatography. International uses this equipment, operated by a trained chemist, to test incoming loads of oil for such things as viscosity, flash point, API gravity, heavy metals, halides, etc. Since 1980, International has received, processed and sold more than 5,000,000 gallons of oil from this facility. The oil processed through the facility includes virgin kerosene, diesel, jet fuel and oils of various grades ranging from ASTM grade numbers 1-4 (the distillates) and ASTM grade numbers 5, 6 and "bunker C" (the residuals). The residual oils are those oils left after the lighter distillates are removed through the vacuum distillation process. The amount of residual oils processed since 1980 is relatively low, less than fifteen percent of the total amount of oils processed at International's facility. Out of 7,000,000 gallons processed in an average year, the plant may receive two or three carloads of grade numbers 5, 6 or bunker C. From 1980 to 1985, approximately 7,000,000 to 12,000,000 gallons of virgin oils were processed at the facility. In each of those years, from 4,000,000 to 7,000,000 gallons of used oil were also processed. Over that five- year period approximately 20,000,000 gallons of used oil were processed and sold through the International facility. International blends virgin oils received at the plant with used oils to meet particular specifications of a customer. It uses its own trucks to collect oil from service stations, automobile dealerships and other industrial accounts. Oil is then delivered to the plant and tested for basic constituents before being placed in an appropriate storage tank. International tests all incoming used oil to see if it meets the criteria for so-called "on spec" used oil or "off spec" used oil. These specifications were established by the EPA in 1985 and adopted by the DER. Used oil meeting these criteria may be burned as fuel in industrial and non-industrial boilers without limitations. The criteria are as follows: Constituent/Property Allowable Level Arsenic 5 ppm maximum Cadmium 2 ppm maximum Chromium 10 ppm maximum Lead 100 ppm maximum Total Halogens 4,000 ppm maximum Flashpoint 100 degrees Fahrenheit minimum International has followed a practice of rejecting incoming used oil which fails to meet the criteria of 1,000 parts per million or less of total halogens, which is the rebuttable threshold presumption of "hazardous waste" oil. International makes an effort to ensure that used oil it receives and processes is thus "on spec." It regularly sends samples to independent laboratories to cross-check its own laboratory testing results. It is selective in its sources of used oil and typically obtains used oil from large companies such as the Mack truck shops, car dealerships and other large volume producers of used oil. These are sources unlikely to be contaminated with any hazardous materials. The "on-spec" used oil accepted by International is placed in separate storage tanks, segregated according to water content and API gravity, viscosity and lead content. It is then blended with virgin oils to meet the specification of various customers. Heat is sometimes supplied in order to drive off water. The used oil undergoes no further treatment or alteration, being merely tested and blended to meet the customer's requirements. Often blending is unnecessary. When a truckload is received, tested and found to meet specifications, it is sometimes directly delivered to a customer. International sometimes obtains used oil without payment from its suppliers and has often purchased it from the generators of used oil. It always sells it to its customers, however. It has a definitely defined industrial market as a fuel commodity and is recognized as having value when sold for such purposes. It may sell for as little as 30 cents per gallon and has sold for much more than that, depending on the market conditions prevailing at the time of sale. It is used both as a burner fuel for industrial and non-industrial boilers, as well as a key constituent in the phosphate beneficiation process. International sells approximately 40 percent of its used oil production to asphalt plants where it is used to fire burners and to rock drying mills, also as a burner fuel. It sells approximately 60 percent of its production of used oil to the phosphate companies for the beneficiation process. In that process, oil is used with other reagents and fatty acids to "float" phosphate out of the rock or ore in which it is contained, allowing it to be skimmed and separated. Although the oil is not burned as a fuel in this process, its use by the phosphate plants substitutes for virgin oils of ATM grade numbers 4 and 5 (heating oil) or in some cases kerosene or number 2 diesel. In 1985, International produced 4,295,101 gallons of used oil which were burned as a fuel by its customers and in 1986 produced 2,221,652 gallons of used oil which were burned as a fuel. The used oil which it sells for the beneficiation process meets DER and EPA standards for "on spec" used oil fuel, except for the lead content, which fact is immaterial to its use for the beneficiation of phosphate. The used oil sold for phosphate purposes does meet pertinent regulatory standards for "off spec" used oil, in any event, so that it could be burned as industrial furnace fuel under EPA and DER rules. The sale of used oil for final use as a burner fuel is very common. Many oil recyclers pick up used oil and take it directly to asphalt plants for burning as fuel without any blending or other treatment. International's sale of 60 percent of its used oil for phosphate processing is unique in the used oil industry, but is attributable to its close proximity to the central Florida phosphate plants. Most oil recycling facilities sell a larger percentage of their product for burner fuel than does International. The used oil which International sells as burner fuel is comparable to heating oil, ASTM grade numbers 2 or 4 and has a similar viscosity, specific gravity and flash point. It can be poured and handled without preheating. Residual oil, however, such as grade numbers 5 and 6 (bunker C) are very viscous and require preheating in industrial boilers or burner furnaces before it can be burned as fuel. The used oil sold by International Petroleum is more similar to ASTM grades 2 and 4 (the distillates) than it is to grades 5 and 6 (the residuals). Petroleum hydrocarbon contamination of the soil and groundwater at the International site was discovered in December 1983 by DER personnel. International retained a consultant to assess the site and determine the nature and extent of any contamination. It has already expended more than $50,000 in an effort to investigate and clean up petroleum contamination at its site. DER conducted a soil and groundwater site investigation in 1985, which showed that hydrocarbons were in the soil and that volatile organics were also present in the groundwater at the site. International has provided all background information requested by DER on site conditions existing prior to cleanup. This was for purposes of showing its entitlement to reimbursement eligibility. The contamination at the site consisted mostly of small leaks, drips and spills associated with loading and unloading railway tank cars, as well as stationary tanks, over at least a five year period. The storage tanks include integral piping systems, and some leakage occurred at hose or pipe connections. The petroleum products placed in the various tanks in the tank farm vary, so that the contamination existing at the site cannot be differentiated or attributed separately to used oils or virgin oils, to distillates (ASTM grades 1-4) or the heavier residuals. All are made up of hydrocarbons and their breakdown products in the ground are essentially indistinguishable. The record does not establish that any major or significant oil spills have occurred at the plant site and does not show that the operators have been particularly negligent or have failed to conform to industry standards. International has already taken remedial action by building high retaining walls and by removing contaminated dirt where repeated drippages occurred near the railroad tracks. Employees have received training to avoid leaks from hoses and pipes and have been instructed to clean up even small spills immediately. Valve equipment has also been upgraded. As a result of these efforts, subsequent testing of the monitoring wells at the site has shown that the groundwater condition has markedly improved and it may be possible that the cleanup action already taken will be sufficient to accord with regulatory standards for groundwater. Used Oil as "Petroleum" or "Petroleum Product" Used oil is derived from crude oil and consists primarily of engine lubricating oil which is a form of hydrocarbon and a special fraction of the original crude oil. The lubricating oil consists of vacuum distilled base oil and atmospheric distillate portions of crude oil produced at a refinery and further refined by processes involving wax removal and solvent extraction. The remaining portion of lubricating oil consists of additives added to the base oil to improve certain physical properties such as rust inhibition and to improve viscosity. Many of these additives, in turn, are substantially comprised of base oil themselves. Used oil also typically contains gasoline which condenses in the crank case, water, gasoline additives, lead sulfates, carbonates or oxides and other partial combustion products of gasoline motor fuel. Lead contained in used engine oil is produced by engines running on tetraethyl lead gasoline. This lead accumulates in the form of lead sulfate, lead carbonate or lead oxide, rather than tetraethyl lead in its original form. The sulfates, carbonates and oxides are insoluble and are not likely to be leached out by groundwater, in contrast to tetraethyl lead. Use of the oil does not change its basic chemical structure. The oil may be contaminated by various impurities resulting from partial combustion of gasoline, from rust, from condensed water and so forth, but these are essentially mechanical mixtures, rather than alterations of the chemical structure of the oil itself. Aside from water, when oil is pumped from the ground at the well, two substances are produced at the well head: crude petroleum oil and natural gas, including casing head gas. Used oil is similar in nature to the petroleum products specifically listed in Section 376.301(10), Florida Statutes (Supp. 1986). The predominant use of used oil is as a fuel, similar to diesel, kerosene and gasoline. A fuel is a material burned as a source of heat, rather than for disposal purposes. It can be either for propulsion purposes or for stationary equipment such as industrial boilers, asphalt plants and the like. Kerosene and diesel fuel are similar in terms of viscosity and BTU value to ASTM grade number 2 fuel oil. Used oil is thicker and more viscous than ASTM grades 2, 3 or 4, but not so viscous as grades 5 or 6. Neither does it have as high a BTU content as grade number 5 fuel oil. ASTM grade number 5 residual oil must be preheated before burning as a fuel. Viscosity is too high for the material to atomize properly at normal temperature. In fact, used oil can be used as a blending agent to blend down or reduce viscosity of grade number 5 oil and reduce the temperature to which number 5 oil must be preheated before burning. With some variance from one sample to another, used oil typically is similar in viscosity and BTU value to ASTM grade number 3 or 4 fuel oil. Gasoline, kerosene, diesel and used oil are all hydrocarbons which burn readily. These materials are mixtures of hydrocarbons, with additives which do not materially affect the properties of the hydrocarbon fuel, or its use as a fuel. Gasoline, in fact, is not classified by ASTM grade. Parenthetically, it thus appears that the Legislature did not intend to limit the scope of "petroleum product" by such considerations as only viscosity and BTU value. "Petroleum products" are commonly used as fuels and are typically stored at service stations or storage tank facilities which can pose a danger of causing inland soil or water contamination, if improperly discharged. Gasoline, kerosene, diesel and used oil are commonly stored in tanks at facilities throughout the state. Used oil does not have any meaningful similarity to the substances specifically excluded from the definition of petroleum or petroleum product by Section 376.301(10), Florida Statutes (Supp. 1986). Used oil, for instance, bears little similarity to liquefied petroleum gas or to petrochemical feed stocks, which latter products are used to supply the raw materials for chemical plants manufacturing petrochemicals of many types. Used oil only is similar to these substances to the extent that it is within the broad family of hydrocarbons derived from crude oil or gases, derived in turn from petroleum wells. Likewise, the ASTM Grades 5 and 6 residual oils are based on the residuum or the heave viscous material left after the distillation process is applied to crude oil. This residuum is the material left that is too heavy to further distill. On the other hand, crank case lubricating oils and transmission oils, which are typically involved in the category "used oil" or "used oil fuel," are derived by the process of vacuum distillation such that they are distillation products, as opposed to residual products. "Bunker C" oils, and marine bunkering oils generally, are residual fuel products and, together with asphalt oil, are not used as fuel, at least not at inland locations. These materials likewise are typically not stored at inland service stations or bulk storage or reclamation facilities and locations. Both the Federal Environmental Protection Agency (EPA) and the Florida DER, in their regulatory scheme concerning used oil, encourage its collection and recycling. Used oil is typically recycled as a fuel and as a lubricant, by being separated from its contaminants by a re-refining process. Indeed, the oil constituent of used oil is not altered by use as lubricating or transmission oil, but rather is rendered in a "used oil" state by being subjected to various contaminants. It is not presently economically viable, given low virgin oil prices, to recycle used oil for lubricating oil. Thus, the two alternatives for disposition of used oil are to deposit it in landfills, a practice now generally prohibited by the DER and other regulatory authorities, or to use it as a fuel. Indeed, the use of used oil as a fuel is about the only practical way to dispose of it safely and legally in view of former uses, such as road oiling for dust control and weed abatement, now being prohibited in potable water aquifer areas. Section 403.75(2), Florida Statutes (1985). Thus, it is not only common and general practice to burn used oil as a boiler fuel and as a fuel in various industrial and utility plants, at the present time-that is almost the only manner in which it can be legally and safely disposed of. The Department itself has a policy encouraging the collection and recycling of used oil, as lubricating oil, fuel or as a feed stock in the manufacturing of other petroleum products. (See IP Exhibits 17, 18 and Joint Exhibit 5 in evidence.) Under EPA regulations which have been adopted by DER, used oil is not regulated as a hazardous waste. Under these regulations, the EPA has adopted a "rebuttable presumption of mixing" in order to distinguish between used oils which have been contaminated through mere use and used oils which have been mixed with hazardous wastes and therefore must be regulated as hazardous wastes or "hazardous waste fuel." Certain hazardous, halogenated constituents, such as chlorinated solvents, are the hazardous wastes typically found mixed with used oil. The "presumption of mixing" provides that any used oil containing greater than 1,000 parts per million of total halogens (such as chlorine, fluorine, bromine, iodine and similar substances) is presumed to have been mixed with a hazardous waste and will be regulated as "hazardous waste fuel" under 40 CFR Part 266, Subpart D, rather than as "used oil fuel" under 40 CFR Part 266, Subpart E. Hazardous waste fuel is essentially a hazardous waste with a BTU value of at least 5,000 BTUs per gallon. Hazardous waste fuel burning is tightly regulated by the EPA and DER. The presumption of mixing can be rebutted through a demonstration that the used oil in question has not been mixed with any hazardous waste. If mixing of used oil with hazardous wastes is known to have occurred, however, the oil is regulated as a hazardous waste when it is burned for energy recovery. Once it has been determined that a particular used oil is a used oil fuel and not a hazardous waste, the used oil falls into one of two categories: "Specification used oil fuel" or "off-specification used oil fuel." Specification used oil contains essentially the same toxic constituents as virgin oil fuels. Off-specification used oil fuel contains elevated levels of toxic components. Most used oil is off-specification, particularly if it is made up of mixtures of several types of used oil. If oil comes from a service station which was used in an engine burning leaded gasoline it would likely result in the used oil from that engine being off-specification due to the toxic lead compounds which would be present in the oil. If the oil was used in an engine which burned unleaded fuel, it is likely that it would be within specification limits for "on-specification used oil." Neither type of used oil is regulated as hazardous waste when burned as fuel, however. For purposes of determining whether an oil fuel is off-specification on on-specification, the EPA has developed a list [at 40 CFR Section 266.40(e): of contaminants, with the allowable levels for each contaminant, below which oil will be determined to be "on specification." Those contaminants are arsenic (5 ppm), cadmium (2 ppm), chromium (10 ppm), lead (100 ppm), with total halogens not exceeding 4,000 ppm in order for used oil to be within specification for nonindustrial burning. Specification used oils may be burned as fuel in nonindustrial boilers, including schools, hospitals, and apartment buildings. Off-specification used oil fuel may be burned in industrial furnaces, industrial boilers, utility boilers and some space heaters meeting certain federal safety requirements. Moreover, EPA regulations allow the blending of off-specification and specification used oil so that the resultant used oil, when burned, meets the specifications for nonindustrial burning. The Department's policy makers who were responsible for the initial decision that used oil is not petroleum or a petroleum product did not consult with certain key personnel in the Department's own used oil section concerning whether oil should be considered as a petroleum or petroleum product. In fact, Mr. Gentry, who is involved in policy making regarding the subject matter of the "Super Act," was not aware that the Department has a program to encourage the burning of used oil as a fuel nor the fact that used oil is extensively burned as a fuel in Florida.
Recommendation Having considered the foregoing Findings of Fact, Conclusions of Law, the evidence of record, the candor and demeanor of the witnesses, and the pleadings and arguments of the parties, it is, therefore RECOMMENDED that the applications of Puckett Oil 4 Company and International Petroleum Corporation for eligibility for reimbursement pursuant to Section 376.3071(12), Florida Statutes (Supp. 1986), be granted. DONE and ENTERED this 7th of June, 1988, in Tallahassee, Florida. P. MICHAEL RUFF Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32399-1550 904/488-9675 FILED with the Clerk of the Division of Administrative Hearings this 7th day of June, 1988. APPENDIX TO RECOMMENDED ORDER CASE NOS. 87-2161 & 87-2465 Petitioners' Proposed Findings of Fact: 1-23. Accepted. 24. Rejected as subordinate to the Hearing Officer's findings on this subject matter. 25-38. Accepted. 39-40. Rejected as subordinate to the Hearing Officer's findings and as not directly material. 41-45. Accepted. 46-48. Rejected as not material and relevant. 49-54. Accepted. 55. Rejected as subordinate to Hearing Officer's findings on this subject matter. 56-58. Accepted. 59. Rejected as subordinate to Hearing Officer's findings on this subject matter. 60-63. Accepted. 64. Rejected as subordinate to the Hearing Officer's findings on this subject and as unnecessary to the resolution of material issues. 65-70. Accepted. 71. Rejected as irrelevant. 72-77. Rejected as subordinate to the Hearing Officer's findings on this subject. Accepted, but not directly relevant and material. Accepted. Respondent's Proposed Findings of Fact: 1-5. Accepted. 6. Rejected as subordinate to the Hearing Officer's findings on this subject matter. 7-8. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as immaterial, in part, because the Hearing Officer, in determining whether the material at the subject sites meets the statutory definitions at issue is not, by the "pleading" confronted with the issue of whether any and all types of "used oil" meet these definitions, rather merely those types comprising the contamination at Petitioner's facility. The Hearing Officer cannot, in this proceeding, issue declaratory statements or advisory opinions. Accepted. Accepted, except for the next to last sentence. 11-12. Accepted. Accepted as to its historic accuracy, but not as a resolution of the essential issue presented. Rejected as immaterial in the absence of a Motion to Compel further, more detailed answers. Accepted as to its historical accuracy, but, for reasons similar to the ruling next above, not as probative of the appropriate, timely raising of the issue of gross negligence. 16-24. Accepted. 25-26. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Accepted. Accepted as to its historical import. 29-38. Accepted. 39. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant evidence of record. 40-43. Accepted. 44-45. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Rejected as not constituting a finding of fact, but, rather, a conclusion of law and statement of policy. Rejected as contrary to the preponderant evidence, as subordinate to the Hearing Officer's findings and as largely immaterial. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter; as being partially immaterial and as a discussion of policy and not a pertinent finding of fact. 51-53. Rejected as constituting legal argument and not a finding of fact. 54-55. Rejected as constituting legal argument. 56. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence. 57-58. Rejected as - subordinate to the Hearing Officer's findings on this subject matter. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter. 61-63. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence and as constituting, in part, legal argument instead of fact finding. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant weight of the evidence. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter, as contrary to the preponderant weight of the evidence and, standing alone, of scant materiality in proving whether used oil is a "petroleum product" or a "fuel commodity." Rejected as contrary to the preponderant weight of the evidence. 78-80. Accepted in part, but not as to its material import and subordinate to the Hearing Officer's findings on this subject matter. 81-84. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant credible evidence. 85. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant credible evidence and as largely immaterial. 86-87. Rejected as immaterial to the ultimate factual and legal issues. 88-89. Accepted. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as contrary to the preponderant credible evidence. Accepted. 92-93. Rejected as subordinate to the Hearing Officer's findings on this subject matter. 94-95. Rejected as subordinate to the Hearing Officer's findings on this subject matter and not in itself material. Rejected as subordinate to the Hearing Officer's findings on this subject matter. Rejected as not comporting with the preponderant weight of the evidence and as immaterial. Rejected as immaterial and irrelevant. Rejected as subordinate to the Hearing Officer's findings and as not directly material and relevant. Rejected as not in accordance with the preponderant weight of the evidence. Rejected as subordinate to the Hearing Officer's 4 findings on this subject matter. 102-103. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as to its purported material import. 104. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as to its purported material import and further as not being in accord with the preponderant weight of the evidence. 105-106. Rejected as constituting legal argument and discussion. 107-109. Rejected as constituting legal argument and discussion and as contrary to the preponderant weight of the evidence. 110-111. Rejected as constituting legal argument and discussion. 112-113. Rejected as constituting legal argument and discussion and as contrary to the preponderant weight of the evidence. Rejected as constituting legal argument and discussion. Accepted but subordinate to the Hearing Officer's findings and not, in itself, material to the legal issue sub judice. Rejected as contrary to the preponderant weight of credible evidence. Rejected as not in itself material and as contrary to the preponderant weight of the credible evidence. Rejected as not in itself material and as contrary to the preponderant weight of the credible evidence and as constituting legal argument and discussion. 119-120. Rejected as subordinate to the Hearing Officer's findings on this subject matter and as to its purported material import and further as not being in accord with the preponderant weight of the evidence. COPIES FURNISHED: Robert D. Fingar, Esquire HUEY, GUILDAY, KUERSTEINER & TUCKER Regulation Suite 510 First Florida Bank Building Post Office Box 1794 Tallahassee, Florida 32302 Dale Twachtmann, Secretary Department of Environmental Blair 2600 Stone Road Tallahassee, Florida 32399. L. Caleen, Jr., Esquire OERTEL & HOFFMAN 2400 Blair Stone Road Tallahassee, Florida 32301 E. Gary Early, Esquire Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32399-2400
The Issue The issue to be determined is whether the applicant, Kanter Real Estate, LLC (Kanter), is entitled to issuance of an Oil and Gas Drilling Permit, No. OG 1366 (the Permit).
Findings Of Fact The Parties Kanter is a foreign limited liability company registered to do business in the State of Florida. Kanter owns 20,000 acres of property in western Broward County, on which it seeks authorization for the drilling of a vertical exploratory well. The exploratory well is to be located on a five-acre site that is subject to an ERP (the Well Site). The Department is the state agency with the power and duty to regulate activities related to the management and storage of surface waters pursuant to chapter 373, Florida Statutes, and to regulate oil and gas resources, including the permitting of activities related to the exploration for and extraction of such resources, pursuant to chapter 377, Florida Statutes. Miramar is a Florida municipal corporation located in Broward County, Florida. Broward County is a political subdivision of the State of Florida with jurisdiction extending to the Kanter property and the Well Site. The Application On July 2, 2015, Kanter submitted its Application for Permit to Drill (Application) to the Department. The proposed Well Site is on land to which Kanter owns the surface rights and subsurface mineral rights. The Application contemplates the drilling of an exploratory well to a depth of approximately 11,800 feet. The Application is not for a production well. The well is to be drilled, and ancillary activities are to be performed on a fill pad of approximately five acres, surrounded by a three-foot high perimeter berm on three sides and the L67-A levee on the fourth. The pad is the subject of an ERP which, as set forth in the Preliminary Statement, is not being challenged. The pad is designed to contain the 100-year, three-day storm. The engineering design incorporates a graded area, berm, and containment with a water control structure and a gated culvert to manipulate the water if necessary. The entire pad is to be covered by a 20 mil PVC liner, is sloped to the center, and includes a steel and concrete sump for the collection of any incidental spills. The pad was designed to contain the full volume of all liquids, including drilling fluid, fuel, and lubricating oil, that are in tanks and containers on the facility. The Application includes technical reports, seismic data, and information regarding the geology and existing producing oil wells of the Upper Sunniland Formation, which Kanter filed for the purpose of demonstrating an indicated likelihood of the presence of oil at the proposed site. The third Request for Additional Information (RAI) did not request additional information regarding the indicated likelihood of the presence of oil at the proposed site. After it submitted its response to the third RAI, Kanter notified the Department of its belief that additional requests were not authorized by law. As a result, the Department completed the processing of the Application without additional RAI’s. On November 16, 2016, the Department entered its Notice of Denial of the Oil and Gas Drilling Permit. The sole basis for denial was that Kanter failed to provide information showing a balance of considerations in favor of issuance pursuant to section 377.241.1/ There was no assertion that the Application failed to meet any standard established by applicable Department rules, Florida Administrative Code Chapters 62C-25 through 62C-30. In particular, the parties included the following stipulations of fact in the Joint Prehearing Stipulation which are, for purposes of this proceeding, deemed as established: The structure intended for the drilling or production of Kanter’s exploratory oil well is not located in any of the following: a municipality; in tidal waters within 3 miles of a municipality; on an improved beach; on any submerged land within a bay, estuary, or offshore waters; within one mile seaward of the coastline of the state; within one mile seaward of the boundary of a local, state or federal park or an aquatic or wildlife preserve; on the surface of a freshwater lake, river or stream; within one mile inland from the shoreline of the Gulf of Mexico, the Atlantic Ocean or any bay or estuary; or within one mile of any freshwater lake, river or stream. The location of Kanter’s proposed oil well is not: within the corporate limits of any municipality; in the tidal waters of the state, abutting or immediately adjacent to the corporate limits of a municipality or within 3 miles of such corporate limits extending from the line of mean high tide into such waters; on any improved beach, located outside of an incorporated town or municipality, or at a location in the tidal waters of the state abutting or immediately adjacent to an improved beach, or within 3 miles of an improved beach extending from the line of mean high tide into such tidal waters; south of 26°00'00? north latitude off Florida’s west coast and south of 27°00'00? north latitude off Florida’s east coast, within the boundaries of Florida’s territorial seas as defined in 43 U.S.C. 1301; north of 26°00'00? north latitude off Florida’s west coast to the western boundary of the state bordering Alabama as set forth in s. 1, Art. II of the State Constitution; or north of 27°00'00? north latitude off Florida’s east coast to the northern boundary of the state bordering Georgia as set forth in s. 1, Art. II of the State Constitution, within the boundaries of Florida’s territorial seas as defined in 43 U.S.C. 1301. 19. The proposed oil well site does not contain Florida panther habitat and is located outside of the primary and secondary habitat zones for the Florida panther. 21. There are no recorded archaeological sites or other historic resources recorded within the area of the proposed oil well site. Kanter submitted a payment of $8,972.00 for its oil and gas permit application on June 30, 2016 pursuant to Rule 62C- 26.002(5)(c), F.A.C. Kanter’s application includes sufficient information and commitments for performance bonds and securities. DEP and Intervenors do not claim that the application lacks the information required in rule 62C-26.002, F.A.C. Kanter’s application includes an organization report that satisfies the requirements of rule 62C-26.003(3), F.A.C. Kanter’s engineering aspects of the site plan for the proposed project site, are appropriate. Kanter’s survey submitted to DEP in support of its application includes a suitable location plat which meets the minimum technical standards for land surveys. Kanter’s application includes an appropriate description of the planned well completion. DEP and Intervenors do not claim that the drilling application lacks the information required by rule 62C-26.003, F.A.C. Kanter’s Application proposes using existing levees to provide access to the proposed Kanter well site. Kanter did not propose to construct additional roads for access. Kanter’s proposed well site is located 332 feet from the L67-A levee, which serves as a roadway for trucks used to perform operations and maintenance on the levees and canals in the area. Kanter’s application does not lack any information required by DEP with respect to the location of roads, pads, or other facilities; nor does it lack any information regarding the minimization of impacts with respect to the location of roads. DEP and Intervenors do not contend that the permit should be denied based upon the proposed “spacing” of the well, or drilling unit, as that term is used in rule 62C-26.004, F.A.C. Kanter’s application includes appropriate plans for the construction of mud tanks, reserve pits, and dikes. Kanter agrees to a reasonable permit condition requiring that if water is to be transported on-site, that it will add additional tanks for the purpose of meeting water needs that would arise during the drilling process. Kanter’s design of the integrated casing, cementing, drilling mud, and blowout prevention programs is based upon sound engineering principles, and takes into account all relevant geologic and engineering data and information. Kanter’s proposed casing plan includes an additional casing string proposed in its response to DEP’s Third Request for Additional Information. This casing plan meets or exceeds the requirements of 62C-27.005, F.A.C. Kanter’s proposed casing and cementing program, as modified, meets or exceeds all applicable statutory and rule criteria.[2/] Kanter’s response and documents provided in response to DEP’s 3rd RAI satisfactorily resolved DEP’s concern regarding the risk of passage of water between different confining layers and aquifers resulting from the physical act of drilling through the layers of water and the intervening soil or earth. Kanter’s application includes a sufficient lost circulation plan. Kanter’s application is not deficient with respect to specific construction requirements which are intended to prevent subsurface discharges. Kanter’s drilling fluids plan is appropriate and is not deficient. Kanter’s blowout prevention equipment and procedures are appropriate and are not deficient. Kanter’s plans for blowout prevention are not insufficient. Kanter’s proposed oil pad is above the 100 year flood elevation and under normally expected circumstances would not be inundated by water if constructed as proposed in Kanter’s application. Kanter’s application includes a Hydrogen Sulfide Safety Plan that includes standards which are consistent with the onshore oil and gas industry standards set forth in the American Petroleum Institutes’ Recommended Practice. DEP and Intervenors do not claim any insufficiencies with respect to Kanter’s Hydrogen Sulfide Gas Contingency Plan, the sufficiency of secondary containment, its construction plans for a protective berm around the drilling site and storage tank areas of sufficient height and impermeability to prevent the escape of pad fluid, its pollution prevention plan, its safety manual, or its spill prevention and cleanup plan. DEP and Intervenors do not contend that the permitting of the well would violate section 377.242(1), F.S., regarding permits for the drilling for, exploring for, or production of oil, gas, or other petroleum products which are to be extracted from below the surface of the land only through the well hole(s). DEP and Intervenors do not contend that Kanter’s application violates the applicable rule criteria for oil and gas permitting set forth in Chapters 62C-25 through 62C-30, Florida Administrative Code. In addition to the foregoing, Kanter is not seeking or requesting authorization to perform “fracking,” and has agreed to a permit condition that would prohibit fracking. As a result of the foregoing, the parties have agreed that the Application meets or exceeds all criteria for an exploratory oil well permit under chapters 62C-25 through 62C-30. The Property Kanter owns two parcels of land totaling 20,000 acres in the area of the proposed Well Site: a northern parcel consisting of approximately 11,000 acres and a southern parcel consisting of approximately 9,000 acres. Kanter assembled its holdings through a series of acquisitions by deeds from 1975 to 1996. The Well Site is to be located within the southern parcel. On August 7, 1944, Kanter’s predecessor in title, Dallas Investment Co., acquired by tax deed all interests in a parcel within the 9,000-acre southern parcel described as “All Section 23 Township 51 South, Range 38 East, 640 Acres,” including, without reservation, the oil, gas, minerals, and phosphate. The evidence of title submitted as part of the Application indicates that a “Kanter” entity first became possessed of rights in Section 23 in 1975. By virtue of a series of transactions extending into 1996, Kanter currently holds fee title to all surface rights, and title to all mineral rights, including rights to oil, gas, and other mineral interests, within Section 23 Township 51 South, Range 38 East. The Well Site specified in the Application is within Section 23, Township 51 South, Range 38 East. Kanter’s property is encumbered by a Flowage Easement that was granted to the Central and Southern Flood Control District in 1950, and is presently held by the South Florida Water Management District (SFWMD). The Flowage Easement guarantees Kanter access to the entire easement property “for the exploration or drilling for, or the developing, producing, storing or removing of oil, gas or other . . . in accordance with sound engineering principles.” Kanter has the legal property right to locate and drill the well, and the exploratory well is consistent with Kanter’s ownership interest. The Well Site is located in a 160-acre (quarter section) portion of the 640-acre tract described above, and is within a “routine drilling unit,” which is the block of land surrounding and assigned to a well. Fla. Admin. Code R. 62C-25.002(20) and 62C-25.002(40). The Kanter property, including the Well Site, is in the historic Everglades. Before efforts to drain portions of the Everglades for development and agricultural uses, water flowed naturally in a southerly direction through land dominated by sawgrass and scattered tree islands. The tree islands were generally shaped by the direction of the water flow. Beginning as early as the late 1800s, dramatically increasing after the hurricane of 1947, and extending well into the 1960s, canals, levees, dikes, and channels were constructed to drain, impound, or reroute the historic flows. Those efforts have led to the vast system of water control structures and features that presently exist in south Florida. The Well Site, and the Kanter property as a whole, is located in Water Conservation Area (WCA)-3. WCA-3 is located in western Broward County and northwestern Miami-Dade County. It was constructed as part of the Central and Southern Florida Flood Control project authorized by Congress in 1948, and was created primarily for flood control and water supply. In the early 1960s, two levees, L67-A and L67-C, were constructed on a line running in a northeast to southwest direction. When constructed, the levees separated WCA-3 into WCA-3A to the west and WCA-3B to the southeast. The Well Site is in WCA-3A.3/ The area between L67-A and L67-C, along with a levee along the Miami Canal, is known as the “Pocket.” There is no water control in the Pocket. Although there is a structure at the south end of the Pocket, it is in disrepair, is rarely -- if ever -- operated, and may, in fact, be inoperable. The Well Site is located within the Pocket, on the southern side of L67-A. L67-A and L67-C, and their associated internal and external canals, have dramatically disrupted sheet flow, altered hydrology, and degraded the natural habitat in the Pocket. Water inputs and outputs are entirely driven by rainfall into the Pocket, and evaporation and transpiration from the Pocket. From a hydrologic perspective, the Pocket is entirely isolated from WCA-3A and WCA-3B. The Pocket is impacted by invasive species, which have overrun the native species endemic to the area and transformed the area into a monoculture of cattails. Vegetation that grows in the Pocket dies in the Pocket. Therefore, there is a layer of decomposing vegetative muck, ooze, and sediment from knee deep to waist deep in the Pocket, which is atypical of a functioning Everglades system. L67-A and L67-C, and their associated internal and external canals, impede wildlife movement, interfering with or preventing life functions of many native wildlife species. The proposed Well Site, and the surrounding Kanter property, is in a rural area where future residential or business development is highly unlikely. The property is removed from urban and industrial areas and is not known to have been used for agriculture. The Department has previously permitted oil wells within the greater Everglades, in areas of a more pristine environmental nature, character, and location than the Pocket. The Raccoon Point wellfield is located 24 miles west of the Proposed Project Site within the Big Cypress National Preserve. It is within a more natural system and has not undergone significant hydrologic changes such as the construction of canals, levees, ditches, and dikes and, therefore, continues to experience a normal hydrologic flow. Mr. Gottfried testified that at Raccoon Point, “you can see the vegetation is maintaining itself because the fact that we don’t have levees, ditches canals, dikes, impacting the area. So you have a diversity of plant life. You have tree islands still. You have the normal flow going down.” The greater weight of evidence shows that the Kanter Well Site is far less ecologically sensitive than property at Raccoon Point on which the Department has previously permitted both exploration and production wells. The Biscayne Aquifer The Biscayne Aquifer exists in almost all of Miami- Dade County, most of Broward County and a portion of the southern end of Palm Beach County. It is thickest along the coast, and thinnest and shallowest on the west side of those counties. The western limit of the Biscayne Aquifer lies beneath the Well Site. The Biscayne Aquifer is a sole-source aquifer and primary drinking water source for southeast Florida. A network of drainage canals, including the L-30, L-31, L-33, and Miami Canals, lie to the east of WCA-3B, and east of the Well Site. Those canals penetrate into the substratum and form a hydrologic buffer for wellfields east of the Well Site, including that operated by Miramar, and isolate the portions of the Biscayne Aquifer near public wellfields from potential impacts originating from areas to their west. The canals provide a “much more hydraulically available source” of water for public wellfields than water from western zones of the Biscayne Aquifer, and in that way create a buffer between areas on either side of the canals. The Pocket is not a significant recharge zone for the Biscayne Aquifer. There is a confining unit comprised of organic soils, muck, and Lake Flint Marl separating the Pocket and the Well Site from the Fort Thompson formation of the Biscayne Aquifer. There is a layer of at least five feet of confining muck under the L67-A levee in the area of the Well Site, a layer that is thicker in the Pocket. The Well Site is not within any 30-day or 120-day protection zones in place for local water supply wells. The fact that the proposed well will penetrate the Biscayne Aquifer does not create a significant risk of contamination of the Biscayne Aquifer. The drilling itself is no different than that done for municipal disposal wells that penetrate through the aquifer much closer to areas of water production than is the Well Site. The extensive casing and cementing program to be undertaken by Kanter provides greater protection for the well, and thus for the aquifer, than is required by the Department’s rules. A question as to the “possibility” that oil could get into the groundwater was answered truthfully in the affirmative “in the definition of possible.” However, given the nature of the aquifer at the Well Site, the hydrological separation of the Well Site and well from the Biscayne Aquifer, both due to the on-site confining layer and to the intervening canals, the degree of casing and cementing, and the full containment provided by the pad, the testimony of Mr. Howard that “it would be very difficult to put even a fairly small amount of risk to the likelihood that oil leaking at that site might possibly actually end up in a well at Miramar” is accepted. The Sunniland Formation The Sunniland Formation is a geologic formation which exists in a region of South Florida known as the South Florida Basin. It is characterized by alternating series of hydrocarbon-containing source rock, dolomite, and limestone of varying porosity and permeability and evaporite anhydrite or mudstone seal deposits. It has Upper Sunniland and Lower Sunniland strata, and generally exists at a depth of up to 12,000 feet below land surface (bls) in the area of the Well Site. Underlying the Sunniland Formation is a formation generally referred to as the “basement.” The basement exists at a depth of 17,000-18,000 feet bls. Oil is produced from organic rich carbonate units within the Lower Cretaceous Sunniland Formation, also known as the Dark Shale Unit of the Sunniland Formation. The oil produced in the Sunniland Formation is generally a product of prehistoric deposits of algae. Over millennia, and under the right conditions of time and pressure, organic material is converted to hydrocarbon oil. The preponderance of the evidence demonstrates that active generating source rock capable of producing hydrocarbons exists in the Sunniland Formation beneath the Kanter property. The preponderance of the evidence also indicates that the oil generated in the Sunniland Formation is at a sufficient depth that it is preserved from microbial degradation, which generally occurs in shallower reservoirs. The Upper Sunniland Formation was formed in the Cretaceous geological period, between 106 and 100 million years ago. Over that period, sea levels rose and fell dramatically, allowing colonies of rudists (a now extinct reef-building clam) and oysters to repeatedly form and die off. Over time, the colonies formed bioherms, which are reef-like buildups of shell elevated off of the base of the sea floor. Over millennia, the bioherms were exposed to conditions, including wave action and exposure to air and rainwater, that enhanced the porosity of the component rudist and oyster shell. Those “patch reefs” were subsequently buried by other materials that formed an impermeable layer over the porous rudist and oyster mounds, and allowed those mounds to become “traps” for oil migrating up from lower layers. A trap is a geological feature that consists of a porous layer overlain by an impervious layer of rock that forms a seal. A trap was described, simplistically, as an upside down bowl. Oil, being lighter than water, floats. As oil is generated in source rock, it migrates up through subterranean water until it encounters a trapping formation with the ability to create a reservoir, and with an impervious layer above the porous layer to seal the trap and prevent further migration, thus allowing the “bowl” to fill. The reservoir is the layer or structure with sufficient porosity and permeability to allow oil to accumulate with its pores. The thickness of the layer determines the volume of oil that the reservoir is capable of retaining. Although rudist mounds are generally considered to be more favorable as traps due to typically higher porosity, oyster mound traps are correlated to producing wells in the Sunniland Formation and are primary producers in the Felda field and the Seminole field. The Lower Sunniland Formation is a fractured carbonate stratum, described by Mr. Aldrich as a rubble zone. It is not a traditional structural trap. Rather, it consists of fractured and crumbling rock thought to be created by basement shear zones or deep-seated fault zones. It has the same source rock as the Upper Sunniland. There is little information on traps in the Lower Sunniland, though there are two fields that produce from that formation. A “play” is a group of prospects or potential prospects that have the same source rock, the same reservoir rock, the same trap style, and the same seal rock to hold in the hydrocarbons. The producing oil fields in the Sunniland Formation, including Raccoon Point, Sunniland, Felda, West Felda, and Lake Trafford are part of a common play known as the Sunniland Trend. The Sunniland Trend is an area of limestone of greater porosity within the Sunniland Formation, and provides a reasonable extrapolation of areas that may be conducive to oil traps. The Sunniland Trend extends generally from Manatee County on the west coast of Florida southeasterly into Broward County and the northwestern portion of Miami-Dade County on the east coast of Florida. The trend corresponds to the ancient Cretaceous shoreline where rudist and oyster bioherms formed as described above. In 2003, the “Mitchell-Tapping” report, named after the husband and wife team, identified two separate trends within the Sunniland Trend, the rudist-dominant West Felda Trend, and the more oyster-based Felda Trend. Both are oil-producing strata. The Felda Trend is more applicable to the Kanter property. Throughout the Sunniland Trend, hydrocarbon reservoirs exist within brown dolomite deposits and rudist and oyster mounds. Dolomite is a porous limestone, and is the reservoir rock found at the productive Raccoon Point oil wellfield. The evidence indicates that a brown dolomite layer of approximately 20 feet underlies the Well Site, and extends in all directions from the Well Site. A preponderance of the evidence indicates that the Kanter property, including the Well Site, is within the Sunniland Trend and its Felda Trend subset.4/ Oil produced from wells in the Sunniland Trend is typically thick, and is not under pressure. The oil does not rise through a bore hole to the surface, but must be pumped. The Raccoon Point Field, which is the closest productive and producing wellfield to the proposed Well Site, is located approximately 24 miles to the west of the Well Site, within the Sunniland Trend. Raccoon Point contains numerous well sites, of which four or five are currently producing, and has produced in the range of 20 million barrels of oil since it began operation in the late 1970s. Cumulative production of oil from proven fields in the South Florida Basin, including fields in the Sunniland Formation, is estimated to be in excess of 160 million barrels. Estimates from the U.S. Geological Service (USGS) indicate that 25 new fields capable of producing five million barrels of oil each are expected to be found within the Lower Cretaceous Shoal Reef Oil Assessment Unit, which extends into the Kanter property. Estimates of the potential reserves reach as high as an additional 200 million barrels of oil. The Dollar Bay Formation Another formation that has potential for oil production is the Lower Cretaceous Dollar Bay Formation, also in the South Florida Basin. The Dollar Bay Formation exists beneath the Kanter property at a shallower depth than the Sunniland Formation, generally at a depth of 10,000 feet in the vicinity of the Well Site. Most of the Dollar Bay prospects are on the east side of the South Florida Basin. Most of the wells in the South Florida Basin are on the west side. Thus, there has not been much in the way of exploration in the Dollar Bay Formation, so there is a lack of data on traps. Dollar Bay has been identified as a known oil-bearing play by the USGS. It is a self-source play, so the source comes from the Dollar Bay Formation itself. Dollar Bay exists both as potential and mature rock. It has known areas of very high total organic content (TOC) source rock; logged reservoir in the formation; and seal rock. There have been three oil finds in the Dollar Bay formation, with at least one commercial production well. Kanter will have to drill through the Dollar Bay Formation to get to the Upper Sunniland formation, thus allowing for the collection of information as to the production potential of the prospect. Although Dollar Bay is not generally the main “target” of the Permit, its potential is not zero. Thus, consideration of the Dollar Bay Formation as a factor in the calculation of risk/success that goes into the decision to drill an exploratory well is appropriate. Initial Exploratory Activities In 1989, Shell Western E&P, Inc. (Shell), conducted extensive seismic exploration in south Florida. Among the areas subject to seismic mapping were two lines -- one line of 36,000 feet mapped along the L67-A levee, directly alongside the Well Site, and the other of approximately 10 miles in length along the Miami Canal levee. The lines intersect on the Kanter property just north of the Well Site. The proposed exploration well is proposed to extend less than 12,000 feet deep. The seismic mapping performed by Shell was capable of producing useful data to that depth. The seismic methodology utilized by Shell produced data with a high degree of vertical and spatial resolution. Given its quality, the Shell data is very reliable. Shell did not use the seismic data generated in the 1980s, and ultimately abandoned activity in the area in favor of larger prospects, leaving the smaller fields typical of south Florida for smaller independent oil companies. The Shell seismic data was purchased by Seismic Exchange, a data brokerage company. In 2014, Kanter purchased the seismic data from Seismic Exchange for the lines that ran through its property. With the purchase, Kanter received the original field tapes, the support data, including surveyors’ notes and observer sheets which describe how the data was acquired, and the recorded data. As a result of advances in computer analysis since the data was collected, the seismic data can be more easily and accurately evaluated. It is not unusual for companies to make decisions on whether to proceed with exploration wells with two lines of seismic data. Mr. Lakin reviewed the data, and concluded that it showed a very promising area in the vicinity of the L67-A levee that was, in his opinion, sufficient to continue with permitting an exploratory oil well. Mr. Lakin described the seismic information in support of the Application as “excellent data,” an assessment that is well-supported and accepted. Mr. Pollister reviewed the two lines of seismic data and opined that the information supports a conclusion that the site is a “great prospect” for producing oil in such quantities as to warrant the exploration and extraction of such products on a commercially profitable basis. Seismic Data Analysis The seismic lines purchased by Kanter consist of line 970, which runs southwest to northeast along the L67-A levee, and a portion of line 998, which runs from northwest to southeast along the Miami Canal levee. The lines intersect at the intersection of the two levees. The data depicts, among others, the seismic reflection from the strata of the Sunniland Trend, and the seismic reflection from the basement. The depiction of the Sunniland Trend shows a discernable rise in the level of the strata, underlain by a corresponding rise in the basement strata. This rise is known as an anticline. An anticline is a location along a geologic strata at which there is an upheaval that tends to form one of the simplest oil traps that one can find using seismic data. In the South Florida Basin, anticlines are typically associated with mounded bioherms. A “closed structure” is an anticline, or structural high, with a syncline, or dip, in every direction. A closed structure, though preferable, is not required in order for there to be an effective trap. Most of the Sunniland oil fields do not have complete closure. They are, instead, stratigraphic traps, in which the formation continues to dip up and does not “roll over.” Where the rock type changes from nonporous to porous and back to nonporous, oil can become trapped in the porous portion of the interval even without “closure.” Thus, even if the “bowl” is tilted, it can still act as a trap. Complete closure is not necessary in much of the Sunniland Trend given the presence of an effective anhydrite layer to form an effective seal.5/ The seismic data of the Kanter property depicts an anticline in the Sunniland Formation that is centered beneath the Well Site at a depth in the range of 12,000 feet bls. Coming off of the anticline is a discernable syncline, or dip in the underlying rock. Applying the analogies used by various witnesses, the anticline would represent the top of the inverted bowl, and the syncline would represent the lip of the bowl. The evidence of the syncline appears in both seismic lines. The Shell seismic data also shows an anhydrite layer above the Sunniland Formation anticline. The same anticline exists at the basement level at a depth of 17,000 to 18,000 feet bls. The existence of the Sunniland formation anticline supported by the basement anticline, along with a thinning of the interval between those formations at the center point, provides support for the data reliably depicting the existence of a valid anticline. A basement-supported anticline is a key indicator of an oil trap, and is a feature commonly relied upon by geophysicists as being indicative of a structure that is favorable for oil production. The seismic data shows approximately 65 feet of total relief from the bottom to the top of the anticline structure, with 50 feet being closed on the back side. The 50 feet of closed anticline appears to extend over approximately 900 acres. There is evidence of other anticlines as one moves northeast along line 970. However, that data is not as strong as that for the structure beneath the Well Site. Though it would constitute a “lead,” that more incomplete data would generally not itself support a current recommendation to drill and, in any event, those other areas are not the subject of the permit at issue. The anticline beneath the well site is a “prospect,” which is an area with geological characteristics that are reasonably predicted to be commercially profitable. In the opinion of Mr. Lakin, the prospect at the location of the proposed Well Site has “everything that I would want to have to recommend drilling the well,” without a need for additional seismic data. His opinion is supported by a preponderance of the evidence, and is credited. Confirmation of the geology and thickness of the reservoir is the purpose of the exploratory well, with the expectation that well logs will provide such confirmation. Risk Analysis Beginning in the 1970s, the oil and gas industry began to develop a business technique for assessing the risk, i.e., the chance of failure, to apply to decisions being made on drilling exploration wells. Since the seminal work by Bob McGill, a systematic science has developed. In 1992, a manual was published with works from several authors. The 1992 manual included a methodology developed by Rose & Associates for assessing risk on prospects. The original author, Pete Rose,6/ is one of the foremost authorities on exploration risk. The Rose assessment method is a very strong mathematical methodology to fairly evaluate a prospect. The Rose method takes aspects that could contribute to finding an oil prospect, evaluates each element, and places it in its perspective. The Rose prospect analysis has been refined over the years, and is generally accepted as an industry standard. The 1992 manual also included a methodology for assessing both plays and prospects developed by David White. The following year, Mr. White published a separate manual on play and prospect analysis. The play and prospect analysis is similar to the Rose method in that both apply mathematical formulas to factors shown to be indicative of the presence of oil. Play and prospect analysis has been applied by much of the oil and gas industry, is used by the USGS in combining play and prospect analysis, and is being incorporated by Rose & Associates in its classes. The evidence is convincing that the White play and prospect analysis taught by Mr. Aldrich is a reasonable and accepted methodology capable of assessing the risk inherent in exploratory drilling. Risk analysis for plays and prospects consists of four primary factors: the trap; the reservoir; the source; and preservation and recovery. Each of the four factors has three separate characteristics. Numeric scores are assigned to each of the factors based on seismic data; published maps and materials; well data, subsurface data, and evidence from other plays and prospects; and other available information. Chance of success is calculated based on the quantity and quality of the data supporting the various factors to determine the likelihood that the prospect will produce flowable hydrocarbons. The analysis and scoring performed by Mr. Aldrich is found to be a reasonable and factually supported assessment of the risk associated with each of the prospects that exist beneath the proposed Well Site and that are the subject of the Application.7/ However, Mr. Aldrich included in his calculation an assessment of the Lower Sunniland Formation. The proposed well is to terminate at a depth of 11,800 feet bls, which is within the Upper Sunniland, but above the Lower Sunniland. Thus, although the Lower Sunniland would share the same source rock, the exploration well will not provide confirmation of the presence of oil. Therefore, it is more appropriate to perform the mathematical calculation to determine the likelihood of success without consideration of the Lower Sunniland prospect. To summarize Mr. Aldrich’s calculation, he assigned a four-percent chance of success at the Well Site for the Dollar Bay prospect. The assignment of the numeric scores for the Dollar Bay factors was reasonable and supported by the evidence. Mr. Aldrich assigned a 20-percent chance of success at the Well Site for the Upper Sunniland play. The assignment of the numeric scores for the Upper Sunniland factors was reasonable and supported by the evidence. In order to calculate the overall chance of success for the proposed Kanter exploratory well, the assessment method requires consideration of the “flip side” of the calculated chances of success, i.e., the chance of failure for each of the prospects. A four-percent chance of success for Dollar Bay means there is a 96-percent (0.96) chance of failure, i.e., that a commercial zone will not be discovered; and with a 20-percent chance of success for the Upper Sunniland, there is an 80-percent (0.80) chance of failure. Multiplying those factors, i.e., .96 x .80, results in a product of .77, or 77 percent, which is the chance that the well will be completely dry in all three zones. Thus, under the industry-accepted means of risk assessment, the 77-percent chance of failure means that there is a 23-percent chance of success, i.e., that at least one zone will be productive. A 23-percent chance that an exploratory well will be productive, though lower than the figure calculated by Mr. Aldrich,8/ is, in the field of oil exploration and production, a very high chance of success, well above the seven-percent average for prospecting wells previously permitted by the Department (as testified to by Mr. Linero) and exceeding the 10- to 15-percent chance of success that most large oil companies are looking for in order to proceed with an exploratory well drilling project (as testified to by Mr. Preston). Thus, the data for the Kanter Well Site demonstrates that there is a strong indication of a likelihood of the presence of oil at the Well Site. Commercial Profitability Commercial profitability takes into account all of the costs involved in a project, including transportation and development costs. Mr. Aldrich testified that the Kanter project would be commercially self-supporting if it produced 100,000 barrels at $50.00 per barrel. His testimony was unrebutted, and is accepted. The evidence in this case supports a finding that reserves could range from an optimistic estimate of 3 to 10 million barrels, to a very (perhaps unreasonably) conservative estimate of 200 barrels per acre over 900 acres, or 180,000 barrels. In either event, the preponderance of the evidence adduced at the hearing establishes an indicated likelihood of the presence of oil in such quantities as to warrant its exploration and extraction on a commercially profitable basis.9/
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department of Environmental Protection enter a final order: Approving the Application for Oil and Gas Drilling Permit No. OG 1366 with the conditions agreed upon and stipulated to by Petitioner, including a condition requiring that if water is to be transported on-site, it will add additional tanks for the purpose of meeting water needs that would arise during the drilling process, and a condition prohibiting fracking; and Approving the application for Environmental Resource Permit No. 06-0336409-001. DONE AND ENTERED this 10th day of October, 2017, in Tallahassee, Leon County, Florida. S E. GARY EARLY Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 10th day of October, 2017.
